UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

~~Form~~FORM 10-Q


þ		~~QUARTERLY REPORT PURSUANT TO SECTION~~Quarterly report pursuant to Section 13 ORor 15(d) ~~OF THE SECURITIES EXCHANGE ACT OF~~of the Securities Exchange Act of 1934

NRG Energy, Inc.

(Registrant’s telephone number, including area code)

CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION

This Quarterly Report onForm 10-Q includes forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. The words “believes”, “projects”, “anticipates”, “plans”, “expects”, “intends”, “estimates” and similar expressions are intended to identify forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors which may cause NRG’s actual results, performance and achievements, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. These factors, risks and uncertainties include the factors described under Risks Related to NRG in Part I, Item 1A, of the Company’s Annual Report onForm 10-K, for the year ended December 31, ~~2007,~~2008, including the following:


	•		General economic conditions, changes in the wholesale power markets and fluctuations in the cost of fuel;

	•		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 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 NRG 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;

	•		NRG’s ability to operate its businesses efficiently, manage capital expenditures and costs tightly, and generate earnings and cash flows from its asset-based businesses in relation to its debt and other obligations;

	•		NRG’s ability to enter into contracts to sell power and procure fuel on acceptable terms and prices;

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

	•		Government regulation, including compliance with regulatory requirements and changes in market rules, rates, tariffs and environmental laws and increased regulation of carbon dioxide and other greenhouse gas emissions;

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

	•		NRG’s ability to borrow additional funds and access capital markets, as well as NRG’s substantial indebtedness and the possibility that NRG may incur additional indebtedness going forward;

	•		Operating and financial restrictions placed on NRG and its subsidiaries that are contained in the indentures governing NRG’s outstanding notes, in NRG’s Senior Credit Facility, and in debt and other agreements of certain of NRG subsidiaries and project affiliates generally;

	•		NRG’s ability to implement itsRepoweringNRG strategy of developing and building new power generation facilities, including new nuclear, ~~units~~wind and ~~wind~~solar projects;

	•		NRG’s ability to implement its econrg strategy of finding ways to meet the challenges of climate change, clean air and protecting ~~our~~ natural resources while taking advantage of business opportunities; ~~and~~

	•		NRG’s ability to achieve its strategy of regularly returning capital to ~~shareholders.~~shareholders;

	•		NRG’s ability to successfully integrate and manage any acquired companies; and

	•		The effects of Exelon’s tender offer and proxy contest on NRG’s ability to effectively manage its business.

Forward-looking statements speak only as of the date they were made, and NRG undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors that could cause NRG’s actual results to differ materially from those contemplated in any forward-looking statements included in this Quarterly Report onForm 10-Q should not be construed as exhaustive.


		GLOSSARY OF TERMS (continued)

FSP FAS 141R-1		FSP No. FAS 141(R)-1“Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies”
FSP FAS 142-3		FSP No. FAS 142-3, “Determination of the Useful Life of Intangible Asset”
FSP FAS 157-3		FSP No. FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active”
FSP FAS 157-4		FSP No. FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly”
GHG		Greenhouse Gases
Gross Generation		The total amount of electric energy produced by generating units and measured at the generating terminal in kWh’s or MWh’s
Heat Rate		A measure of thermal efficiency computed by dividing the total BTU content of the fuel burned by the resulting kWh’s generated. Heat rates can be expressed as either gross or net heat rates, depending whether the electricity output measured is gross or net generation and is generally expressed as BTU per net kWh.
Hedge Reset		Net settlement of long-term power contracts and gas swaps by negotiating prices to current market completed in November 2006
IGCC		Integrated Gasification Combined Cycle
IRS		Internal Revenue Service
ISO		Independent System Operator, also referred to as Regional Transmission ~~Organization,~~Organizations, or RTO
ISO-NE		ISO New England Inc.
ITISA		Itiquira Energetica S.A.
kV		Kilovolts
kW		Kilowatts
kWh		Kilowatt-hours
~~LFRM~~		~~Locational Forward Reserve Market~~
LIBOR		London Inter-Bank Offer Rate
~~LMP~~		~~Locational Marginal Prices~~
LTIP		Long-Term Incentive Plan
MACT		Maximum Achievable Control Technology
Merit Order		A term used for the ranking of power stations in ~~terms of increasing~~ order of ~~fuel costs~~ascending marginal cost
MIBRAG		Mitteldeutsche Braunkohlengesellschaft mbH
Moody’s		Moody’s Investors Services, Inc. — a credit rating agency
MMBtu		Million British Thermal Units
MOU		Memorandum of Understanding


		~~GLOSSARY OF TERMS (cont’d)~~

MRTU		Market Redesign and Technology Upgrade
MVA		Megavolt-ampere
MW		Megawatts
MWh		Saleable megawatt hours net of internal/parasitic loadmegawatt-hours
MWt		Megawatts Thermal
NAAQS		National Ambient Air Quality ~~Standard~~Standards
NEPOOL		New England Power Pool
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, 2008
Net Capacity Factor		The net amount of electricity that a generating unit produces over a period of time divided by the net amount of electricity it could have produced if it had run at full power over that time period. The net amount of electricity produced is the total amount of electricity generated minus the amount of electricity used during generation.
Net Exposure		Counterparty credit exposure to NRG, net of collateral
~~NiMo~~Net Generation		~~Niagara Mohawk Power Corporation~~The net amount of electricity produced, expressed in kWh’s or MWh’s, that is the total amount of electricity generated (gross) minus the amount of electricity used during generation.
NINA		Nuclear Innovation North America LLC
~~NOx~~ NO_x		Nitrogen oxide
NOL		Net Operating Loss
NOV		Notice of Violation
NPNS		Normal Purchase Normal Sale
NRC		United States Nuclear Regulatory Commission
NRG Retail		NRG Retail LLC
NSR		New Source Review
NYISO		New York Independent System Operator
~~NYPA~~		~~New York Power Authority~~
OCI		Other Comprehensive Income


		GLOSSARY OF TERMS (continued)

Padoma		Padoma Wind Power LLC
Phase II 316(b) Rule		A section of the Clean Water Act regulating cooling water intake structures
PJM		PJM Interconnection, LLC
PJM ~~Market~~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
PMI		NRG Power Marketing, LLC, a wholly-owned subsidiary of NRG which procures transportation and fuel for the Company’s generation facilities, sells the power from these facilities, and manages all commodity trading and hedging for NRG
Powder River Basin, or PRB, Coal		Coal produced in northeastern Wyoming and southeastern Montana, which has low sulfur content
PPA		Power Purchase Agreement
~~PPM~~		~~Parts per Million~~
~~PSD~~		~~Prevention of Significant Deterioration~~
PUCT		~~The~~ Public Utility Commission of Texas
Reliant Retail		Reliant Energy Inc.’s Texas electric retail business operations
Repowering		~~Replacing, rebuilding,~~Technologies utilized to replace, rebuild, or ~~redeveloping~~redevelop major portions of an existing electrical generating facility, not only to achieve a substantial emissions reduction, but also to increase facility capacity, and improve system efficiency
RepoweringNRG		NRG’s program designed to develop, finance, construct and operate new, highly efficient, environmentally responsible capacity over the next decade
Revolving Credit Facility		NRG’s $1 billion senior secured revolving credit facility which matures on February 2, 2011
RGGI		Regional Greenhouse Gas Initiative
~~RMR~~ROIC		~~Reliability Must-Run~~Return on Invested Capital
RPM		Reliability Pricing Model — term for capacity market in PJM market
RTO		Regional Transmission Organization, also referred to as an Independent System ~~Operator,~~Operators, or ISO
S&P		Standard & Poor’s, a credit rating agency
Sarbanes-Oxley		~~Sarbanes-Oxley~~Sarbanes — Oxley Act of 2002 (as amended)
SEC		United States Securities and Exchange Commission
Securities Act		The Securities Act of 1933, as amended
Senior Credit Facility		NRG’s senior secured facility, which is comprised of a Term ~~B loan facility~~Loan Facility and a $1.3 billion Synthetic Letter of Credit Facility which mature on February 1, 2013, and a $1 billion Revolving Credit Facility, which matures on February 2, 2011
Senior Notes		The Company’s $4.7 billion outstanding unsecured senior notes consisting of $1.2 billion of 7.25% senior notes due 2014, $2.4 billion of 7.375% senior notes due 2016 and $1.1 billion of 7.375% senior notes due 2017
SFAS		Statement of Financial Accounting Standards issued by the FASB
SFAS 109		SFAS No. 109,“Accounting for Income Taxes”
SFAS 123R		SFAS No. 123 (revised 2004),“Share-Based Payment”
SFAS 133		SFAS No. 133,“Accounting for Derivative Instruments and Hedging Activities” as amended
SFAS 141R		SFAS No. 141 (revised 2007), “Business Combinations”
SFAS 142		SFAS No. 142,“~~Business Combinations”~~Goodwill and Other Intangible Assets”
SFAS 157		SFAS No. 157,“Fair Value ~~Measurements~~Measurement””


		~~GLOSSARY OF TERMS (cont’d)~~

SFAS 160		SFAS No. 160, ““Noncontrolling Interest in Consolidated Financial ~~Statements”~~Statements”
SFAS 161		SFAS No. 161, ““Disclosure about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. ~~133~~133””
Sherbino		Sherbino I Wind Farm LLC
SO₂		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”
STP		South Texas Project — ~~Nuclear~~nuclear generating facility located near Bay City, Texas in which NRG owns a 44% ~~interest~~Interest
STPNOC		South Texas Project Nuclear Operating Company
Synthetic Letter of Credit Facility		NRG’s $1.3 billion senior secured synthetic letter of credit facility which matures on February 1, 2013
TANE		Toshiba American Nuclear Energy Corporation
TANE Facility		NINA’s $500 million credit facility from TANE which matures on February 24, 2012
TCEQ		Texas Commission on Environmental Quality


		GLOSSARY OF TERMS (continued)

Term ~~B loan~~Loan Facility		A senior first priority secured term loan which matures on February 1, 2013, and is included as part of NRG’s Senior Credit Facility
Texas Genco		Texas Genco LLC, now referred to as the Company’s Texas ~~region~~Region
~~Texas West~~Tonnes		~~The West Zone~~Metric tonnes, which are units of ~~Texas’ ERCOT power market~~mass or weight in the metric system each equal to 2,205 lbs and are the global Measurement for GHG
~~Tosli~~Uprate		~~Tosli Acquisition B.V.~~A sustainable increase in the electrical rating of a generating facility
US		United States of America
USEPA		United States Environmental Protection Agency
US GAAP		Accounting principles generally accepted in the United States
VAR		Value at Risk
WCP		WCP (Generation) Holdings, ~~LLC~~Inc.

PART I — FINANCIAL INFORMATION


~~ITEM 1 —~~	~~CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES~~

ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)

Three Months Ended September 30 Nine Months Ended September 30

(In millions, except for per share amounts) 2008 2007 2008 2007

Operating Revenues

Total operating revenues $ 2,690 $ 1,772 $ 5,308 $ 4,607

Operating Costs and Expenses

Cost of operations 997 939 2,812 2,560
Depreciation and amortization 156 160 478 481
General and administrative 75 78 233 234
Development costs 13 49 29 108

Total operating costs and expenses 1,241 1,226 3,552 3,383
Gain on sale of assets — — — 16

Operating Income
1,449 546 1,756 1,240

Other Income/(Expense)

Equity in earnings of unconsolidated affiliates 58 19 35 40
Other (loss)/income, net (7 ) 14 14 44
Refinancing expense — — — (35 )
Interest expense (186 ) (169 ) (481 ) (520 )

Total other expense (135 ) (136 ) (432 ) (471 )

Income From Continuing Operations Before Income Taxes
1,314 410 1,324 769
Income tax expense 530 145 531 300

Income From Continuing Operations
784 265 793 469
Income from discontinued operations, net of income tax expense — 3 172 13

Net Income
784 268 965 482
Dividends for preferred shares 13 13 41 41

Income Available for Common Stockholders
$ 771 $ 255 $ 924 $ 441
Weighted average number of common shares outstanding — basic 235 239 236 241
Income from continuing operations per weighted average common share — basic $ 3.28 $ 1.05 $ 3.19 $ 1.78
Income from discontinued operations per weighted average common share — basic — 0.02 0.73 0.05

Net Income per Weighted Average Common Share — Basic
$ 3.28 $ 1.07 $ 3.92 $ 1.83

Weighted average number of common shares outstanding — diluted 277 285 278 287
Income from continuing operations per weighted average common share — diluted $ 2.83 $ 0.92 $ 2.83 $ 1.61
Income from discontinued operations per weighted average common share — diluted — 0.01 0.62 0.05

Net Income per Weighted Average Common Share — Diluted
$ 2.83 $ 0.93 $ 3.45 $ 1.66


	Three months ended March 31,
(In millions, except for per share amounts)	2009			2008

Operating Revenues
Total operating revenues	$	1,658		$	1,302

Operating Costs and Expenses
Cost of operations		766			804
Depreciation and amortization		169			161
General and administrative		95			75
Development costs		13			12

Total operating costs and expenses		1,043			1,052

Operating Income		615			250

Other Income/(Expense)
Equity in earnings/(losses) of unconsolidated affiliates		22			(4	)
Other (loss)/income, net		(3	)		9
Interest expense		(138	)		(156	)

Total other expense		(119	)		(151	)

Income From Continuing Operations Before Income Taxes		496			99
Income tax expense		298			54

Income From Continuing Operations		198			45
Income from discontinued operations, net of income taxes		—			4

Net Income attributable to NRG Energy, Inc.		198			49
Dividends for preferred shares		14			14

Income Available for NRG Energy, Inc. Common Stockholders	$	184		$	35


Earnings per share attributable to NRG Energy, Inc. Common Stockholders
Weighted average number of common shares outstanding — basic		237			236
Income from continuing operations per weighted average common share — basic	$	0.78		$	0.13
Income from discontinued operations per weighted average common share — basic		—			0.02

Net Income per Weighted Average Common Share — Basic	$	0.78		$	0.15

Weighted average number of common shares outstanding — diluted		275			245
Income from continuing operations per weighted average common share — diluted	$	0.70		$	0.12
Income from discontinued operations per weighted average common share — diluted		—			0.02

Net Income per Weighted Average Common Share — Diluted	$	0.70		$	0.14


Amounts attributable to NRG Energy, Inc.:
Income from continuing operations, net of income taxes	$	198		$	45
Income from discontinued operations, net of income taxes		—			4

Net Income	$	198		$	49

See notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS

September 30, 2008 December 31, 2007

(In millions, except shares) (unaudited)

ASSETS

Current Assets

Cash and cash equivalents $ 1,483 $ 1,132
Restricted cash 32 29
Accounts receivable, less allowance for doubtful accounts of $3 and $1, respectively 531 482
Inventory 456 451
Derivative instruments valuation 4,190 1,034
Deferred income taxes — 124
Cash collateral paid in support of energy risk management activities 544 85
Prepayments and other current assets 203 174
Current assets — discontinued operations — 51

Total current assets 7,439 3,562

Property, plant and equipment, net of accumulated depreciation of $2,184 and $1,695, respectively
11,472 11,320

Other Assets

Equity investments in affiliates 428 425
Notes receivable and capital lease, less current portion 450 491
Goodwill 1,786 1,786
Intangible assets, net of accumulated amortization of $425 and $372, respectively 822 873
Nuclear decommissioning trust fund 333 384
Derivative instruments valuation 816 150
Other non-current assets 134 176
Intangible assets held-for-sale 3 14
Non-current assets — discontinued operations — 93

Total other assets 4,772 4,392

Total Assets
$ 23,683 $ 19,274

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities

Current portion of long-term debt and capital leases $ 122 $ 466
Accounts payable 367 384
Derivative instruments valuation 4,022 917
Deferred income taxes 16 —
Cash collateral received in support of energy risk management activities 154 14
Accrued expenses and other current liabilities 629 459
Current liabilities — discontinued operations — 37

Total current liabilities 5,310 2,277

Other Liabilities

Long-term debt and capital leases 8,059 7,895
Nuclear decommissioning reserve 320 307
Nuclear decommissioning trust liability 252 326
Deferred income taxes 1,083 843
Derivative instruments valuation 1,158 759
Out-of-market contracts 336 628
Other non-current liabilities 568 412
Non-current liabilities — discontinued operations — 76

Total non-current liabilities 11,776 11,246

Total Liabilities
17,086 13,523

Minority interest 7 —
3.625% convertible perpetual preferred stock (at liquidation value, net of issuance costs) 247 247
Commitments and Contingencies

Stockholders’ Equity

Preferred stock (at liquidation value, net of issuance costs) 892 892
Common stock 3 3
Additional paid-in capital 4,135 4,092
Retained earnings 2,194 1,270
Less treasury stock, at cost — 29,242,483 and 24,550,600 shares, respectively (823 ) (638 )
Accumulated other comprehensive loss (58 ) (115 )

Total Stockholders’ Equity
6,343 5,504

Total Liabilities and Stockholders’ Equity
$ 23,683 $ 19,274


	March 31, 2009			December 31, 2008
(In millions, except shares)	(unaudited)

ASSETS
Current Assets
Cash and cash equivalents	$	1,188			$ 1,494
Funds deposited by counterparties		1,275			754
Restricted cash		17			16
Accounts receivable, less allowance for doubtful accounts of $3 and $3, respectively		399			464
Inventory		488			455
Derivative instruments valuation		3,862			4,600
Cash collateral paid in support of energy risk management activities		178			494
Prepayments and other current assets		258			215

Total current assets		7,665			8,492

Property, plant and equipment, net of accumulated depreciation of $2,524 and $2,343, respectively		11,544			11,545

Other Assets
Equity investments in affiliates		494			490
Capital leases and note receivable, less current portion		403			435
Goodwill		1,718			1,718
Intangible assets, net of accumulated amortization of $191 and $335, respectively		815			815
Nuclear decommissioning trust fund		286			303
Derivative instruments valuation		1,148			885
Other non-current assets		125			125

Total other assets		4,989			4,771

Total Assets	$	24,198			$ 24,808

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	263			$ 464
Accounts payable		358			451
Derivative instruments valuation		3,000			3,981
Deferred income taxes		418			201
Cash collateral received in support of energy risk management activities		1,277			760
Accrued expenses and other current liabilities		269			724

Total current liabilities		5,585			6,581

Other Liabilities
Long-term debt and capital leases		7,685			7,697
Nuclear decommissioning reserve		288			284
Nuclear decommissioning trust liability		195			218
Deferred income taxes		1,303			1,190
Derivative instruments valuation		420			508
Out-of-market contracts		271			291
Other non-current liabilities		737			669

Total non-current liabilities		10,899			10,857

Total Liabilities		16,484			17,438

3.625% convertible perpetual preferred stock (at liquidation value, net of issuance costs)		247			247
Commitments and Contingencies
Stockholders’ Equity
Preferred stock (at liquidation value, net of issuance costs)		406			853
Common stock		3			3
Additional paid-in capital		4,510			4,350
Retained earnings		2,607			2,423
Less treasury stock, at cost — 17,200,777 and 29,242,483 shares, respectively		(532	)		(823	)
Accumulated other comprehensive income		466			310
Noncontrolling interest		7			7

Total Stockholders’ Equity		7,467			7,123

Total Liabilities and Stockholders’ Equity	$	24,198			$ 24,808

See notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

(In millions)

Nine Months Ended September 30, 2008 2007

Cash Flows from Operating Activities

Net income $ 965 $ 482
Adjustments to reconcile net income to net cash provided by operating activities Distributions and equity in (earnings) of unconsolidated affiliates (24 ) (23 )
Depreciation and amortization 478 483
Amortization of nuclear fuel 31 42
Amortization and write-off of financing costs and debt discount/premiums 22 59
Amortization of intangibles and out-of-market contracts (226 ) (112 )
Changes in deferred income taxes and liability for unrecognized tax benefits 427 232
Changes in nuclear decommissioning trust liability 8 23
Changes in derivatives (110 ) 41
Changes in collateral deposits supporting energy risk management activities (320 ) (107 )
Loss/(gain) on disposals and sales of assets 13 (16 )
Gain on sale of discontinued operations (273 ) —
Gain on sale of emission allowances (52 ) (31 )
Amortization of unearned equity compensation 21 19
Cash provided/(used) by changes in other working capital 81 (116 )

Net Cash Provided by Operating Activities
1,041 976

Cash Flows from Investing Activities

Capital expenditures (649 ) (309 )
Increase in restricted cash, net (3 ) (18 )
Decrease in notes receivable 20 26
Purchases of emission allowances (6 ) (152 )
Proceeds from sale of emission allowances 75 170
Investments in nuclear decommissioning trust fund securities (441 ) (193 )
Proceeds from sales of nuclear decommissioning trust fund securities 434 170
Proceeds from sale of discontinued operations, net of cash divested 241 —
Proceeds from sale of assets 14 57
Decrease in trust fund balances — 19
Equity investment in unconsolidated affiliate (17 ) —
Other — (2 )

Net Cash Used by Investing Activities
(332 ) (232 )

Cash Flows from Financing Activities

Payment of dividends to preferred stockholders (41 ) (41 )
Payment of financing element of acquired derivatives (49 ) —
Payment for treasury stock (185 ) (268 )
Proceeds from issuance of common stock, net of issuance costs 8 —
Proceeds from sale of minority interest in subsidiary 50 —
Proceeds from issuance of long-term debt 20 1,411
Payment of deferred debt issuance costs (2 ) (5 )
Payments for short and long-term debt (202 ) (1,472 )

Net Cash Used by Financing Activities
(401 ) (375 )

Change in cash from discontinued operations 43 (16 )
Effect of exchange rate changes on cash and cash equivalents — 7

Net Increase in Cash and Cash Equivalents
351 360
Cash and Cash Equivalents at Beginning of Period
1,132 777

Cash and Cash Equivalents at End of Period
$ 1,483 $ 1,137


(In millions)
Three months ended March 31,	2009			2008

Cash Flows from Operating Activities
Net income	$	198		$	49
Adjustments to reconcile net income to net cash provided by operating activities
Distributions and equity in (earnings)/losses of unconsolidated affiliates		(22	)		6
Depreciation and amortization		169			161
Amortization of nuclear fuel		10			15
Amortization of financing costs and debt discount/premiums		9			11
Amortization of intangibles and out-of-market contracts		(34	)		(66	)
Changes in deferred income taxes and liability for unrecognized tax benefits		299			49
Changes in nuclear decommissioning trust liability		6			9
Changes in derivatives		(304	)		132
Changes in collateral deposits supporting energy risk management activities		312			(150	)
Gain on sale of assets		(1	)		—
Gain on sale of emission allowances		(7	)		(14	)
Amortization of unearned equity compensation		7			7
Changes in option premiums collected		(270	)		15
Cash used by changes in other working capital		(233	)		(164	)

Net Cash Provided by Operating Activities		139			60

Cash Flows from Investing Activities
Capital expenditures		(233	)		(164	)
Increase in restricted cash, net		(1	)		(10	)
Decrease in notes receivable		3			9
Purchases of emission allowances		(35	)		(1	)
Proceeds from sale of emission allowances		8			31
Investments in nuclear decommissioning trust fund securities		(83	)		(144	)
Proceeds from sales of nuclear decommissioning trust fund securities		78			135
Proceeds from sale of assets		4			12

Net Cash Used by Investing Activities		(259	)		(132	)

Cash Flows from Financing Activities
Payment of dividends to preferred stockholders		(14	)		(14	)
Receipt from/(payment of) financing element of acquired derivatives		40			(1	)
Payment for treasury stock		—			(55	)
Proceeds from issuance of common stock, net of issuance costs		—			2
Payment of deferred debt issuance costs		(1	)		(2	)
Payments for short and long-term debt		(209	)		(154	)

Net Cash Used by Financing Activities		(184	)		(224	)

Change in cash from discontinued operations		—			(6	)
Effect of exchange rate changes on cash and cash equivalents		(2	)		4

Net Decrease in Cash and Cash Equivalents		(306	)		(298	)
Cash and Cash Equivalents at Beginning of Period		1,494			1,132

Cash and Cash Equivalents at End of Period	$	1,188		$	834

See notes to condensed consolidated financial statements.

910

NRG ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

~~(Unaudited)~~Note 1 — Basis of Presentation


~~Note 1 —~~	~~Basis of Presentation~~

NRG Energy, Inc., or NRG or the Company, is a wholesale power generation company with a significant presence in major competitive power markets in the United States. NRG is engaged in the ownership, development, construction and operation of power generation facilities, the transacting in and trading of fuel and transportation services, and the trading of energy, capacity and related products in the United States and select international markets.

The accompanying unaudited interim condensed consolidated financial statements have been prepared in accordance with the SEC’s regulations for interim financial information and with the instructions toForm 10-Q. Accordingly, they do not include all of the information and notes required by generally accepted accounting principles for complete financial statements. The accounting policies NRG follows are set forth in Note 2,Summary of Significant Accounting Policies, to the Company’s financial statements in its Annual Report onForm 10-K for the year ended December 31, ~~2007.~~2008. The following notes should be read in conjunction with such policies and other disclosures in theForm 10-K. Interim results are not necessarily indicative of results for a full year.

In the opinion of management, the accompanying unaudited interim consolidated financial statements contain all material adjustments consisting of normal and recurring accruals necessary to present fairly the Company’s consolidated financial position as of ~~September 30, 2008,~~March 31, 2009, the results of operations for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2009 and 2008, ~~and 2007,~~ and cash flows for the ~~nine~~three months ended ~~September 30, 2008~~March 31, 2009 and ~~2007.~~2008. Certain prior-year amounts have been reclassified for comparative purposes.

Recent Developments – Reliant Retail Acquisition

On March 2, 2009, NRG announced that, acting through its wholly owned subsidiary, NRG Retail LLC, or NRG Retail, it had entered into a membership interest purchase agreement to acquire Reliant Energy Inc.’s Texas electric retail business operations, or Reliant Retail, for a purchase price of $287.5 million cash, and the return of Reliant Retail’s net working capital as of the closing date. NRG will also guarantee certain obligations of NRG Retail in connection with the purchase.

NRG has arranged with Merrill Lynch Commodities, Inc., or Merrill Lynch, the current credit provider of Reliant, to provide continuing credit support to the retail business subsequent to closing. The Company negotiated a transitional credit sleeve facility, or CSRA, with Merrill Lynch under which NRG will contribute $200 million of cash into the retail entity. In conjunction with the CSRA, NRG, Reliant Retail, Merrill Lynch and certain counterparties will enter into offsetting trades to move collateral with respect to NRG’s in-the-money positions in order to reduce Merrill Lynch’s actual and contingent collateral on Reliant Retail’s out-of-money positions. The CSRA will provide collateral support for the retail enterprise up to November 1, 2010, while a transition to NRG supplying the retail business’ power requirements occurs, with limited ongoing collateral requirements. NRG will also have two potential cash contribution obligations: (i) in October 2009 of $250 million if a threshold level to be determined at closing is exceeded, and (ii) in October 2010 for up to $400 million at the sleeve unwind. The monthly fees for this sleeve facility is 5.875% on an annualized basis of the predetermined exposure as defined in the CSRA.

Each of the parties’ obligation to consummate the acquisition of Reliant Retail is subject to certain customary conditions and regulatory approvals, including: (i) the absence of any event or circumstance that would have a material adverse effect on the other party’s business, assets, properties, liabilities, condition (financial or otherwise) or results of operations, taken as a whole; and (ii) the receipt of required regulatory approvals, which have been obtained. On March 30, 2009, the Federal Trade Commission, together with the US Department of Justice, granted early termination of the pre-merger waiting period pursuant to the Hart Scott Rodino Antitrust Improvements Act. Subject to the remaining foregoing conditions, the transaction is expected to be consummated effective May 1, 2009.

Use of Estimates

The preparation of consolidated financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions. These estimates and assumptions impact the reported amount of assets and liabilities and disclosures of contingent assets and liabilities as of the date of the consolidated financial statements. They also impact the reported amount of net earnings during the reporting period. Actual results could be different from these estimates.

Cash and Cash Equivalents

Cash and cash equivalents at ~~September 30, 2008~~March 31, 2009 are predominantly held in money market funds invested in treasury securities, or treasury repurchase ~~agreements.~~

agreements or government agency debt.

~~Investment Accounted for by the Equity Method~~

In February 2008, a wholly-owned subsidiary of NRG entered into a 50/50 joint venture with a subsidiary of BP Alternative Energy North America Inc., or BP, to build and own the Sherbino I Wind Farm LLC, or Sherbino. This is a 150 MW wind project consisting of 50 Vestas 3 MW wind turbine generators, located in the West Zone of Texas’ ERCOT power market, or Texas West. The project will be funded through a combination of equity contributions from the owners and non-recourse project-level debt. NRG delivered a $59 million promissory note to Sherbino to support its initial capital contribution, payable no later than December 1, 2008, made an additional $17 million cash contribution in April 2008, and expects to contribute another $11 million by year end, bringing its total expected equity contribution to approximately $87 million. NRG has posted a letter of credit in this amount. NRG’s maximum exposure to loss is limited to its expected equity investments. Sherbino commenced commercial operations in October 2008.

Sherbino has entered into a long-term natural gas swap to mitigate a portion of power price risk for its expected power generation. As the changes in natural gas prices and in Texas West power prices do not meet the required correlation for cash flow hedge accounting, Sherbino will account for the natural gas swap hedge under mark-to-market accounting.

NRG accounts for its investment in Sherbino under the equity method of accounting. NRG’s share of mark-to-market results of the natural gas swap, a loss of $9 million for the nine months ended September 30, 2008, is included in NRG’s equity in earnings of Sherbino. NRG’s investment at September 30, 2008, net of its promissory note commitment, is $7 million, which is included in~~“Equity Investments in Affiliates”~~ ~~on the condensed consolidated balance sheet.~~

Other Cash Flow Information

NRG’s non-cash investing activities for the ~~nine~~three months ended ~~September 30, 2008~~March 31, 2009 included capital expenditures of ~~$60~~$3 million for which the associated liability is reflected within accrued expenses.

Recent Accounting Developments

~~The Company partially adopted SFAS No. 157,~~~~Fair Value Measurements~~, or SFAS 157, on January 1, 2008, delaying application for non-financial assets and non-financial liabilities as permitted. This statement defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. In February 2008, the Financial Accounting Standards Board, or FASB, issued FASB Staff Position, or FSP,~~No. FAS 157-1,~~Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13~~, which amends SFAS 157 to exclude SFAS Statement No. 13,~~~~Accounting for Leases~~~~, or SFAS 13, and other accounting pronouncements that address fair value measurements for purposes of lease classification or measurement under SFAS 13. In February 2008, the FASB also issued FSPNo. FAS 157-2,~~~~Effective Date of FASB Statement No. 157~~, which permitted delayed application of this statement for non-financial assets and non-financial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. The partial adoption of SFAS 157 did not have a material impact on the Company’s consolidated financial position, statement of operations, and cash flows. The Company is currently evaluating the impact of the deferred portion of SFAS 157 on the Company’s consolidated financial position, statement of operations, and cash flows.

The Company adopted ~~SFAS No. 159,~~~~The Fair Value Option for Financial Assets and Financial Liabilities-including an amendment of FASB Statement No. 115~~, or SFAS 159, on January 1, 2008. This statement provides entities with an option to measure and report selected financial assets and liabilities at fair value. The Company does not intend to apply this standard to any of its eligible assets or liabilities; therefore, there was no impact on NRG’s consolidated financial position, results of operations, or cash flows.

~~The Company adopted FSPFIN 39-1,~~~~Amendment of FASB Interpretation No. 39~~~~, or FSPFIN 39-1,~~ ~~which amends FIN 39,~~~~Offsetting of Amounts Related to Certain Contracts~~~~, on January 1, 2008. FSPFIN 39-1~~ impacts entities that enter into master netting arrangements as part of their derivative transactions. Under the guidance in this FSP, entities may choose to offset derivative positions in the financial statements against the fair value of amounts recognized as cash collateral paid or received under those arrangements. The Company chose not to offset positions as defined in this FSP; therefore there was no impact on NRG’s consolidated financial position, results of operations, or cash flows.

NRG has non-qualified stock options for which it has insufficient historical exercise data and therefore estimates the expected term using the simplified method, as allowed under Staff Accounting Bulletin, or SAB, No. 107,~~Share Based Payment~~~~, or SAB 107. In December 2007, the SEC issued SAB No. 110,~~~~Certain Assumptions Used in Valuation Methods~~, which eliminates the December 31, 2007 expiration of SAB 107’s permission to use this simplified method. NRG will therefore continue to use this simplified method, for as long as the Company deems it to be the most appropriate method.

~~In December 2007, the FASB issued~~ SFAS No. 141 (revised 2007),Business Combinations, or SFAS ~~141R. This statement applies~~141R, on January 1, 2009. The provisions of SFAS 141R are applied prospectively to ~~all~~ business combinations for which the acquisition date ~~is on or~~occurs after ~~the beginning of an entity’s first annual reporting period beginning on or after December 15, 2008.~~January 1, 2009. The statement requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at fair value at the acquisition date. It also recognizes and measures the goodwill acquired or a gain from a bargain purchase in the business combination and determines what information to disclose to enable users of an entity’s financial statements to evaluate the nature and financial effects of the business combination. In addition, transaction costs are required to be expensed as incurred. The Company has applied the provisions of SFAS 141R to the Reliant Retail acquisition, and has expensed $12 million in transactions costs related to the acquisition during the three months ended March 31, 2009. As discussed further in Note 12,Income Taxes, ~~SFAS 141R~~any future reductions to existing net deferred tax assets or valuation allowances, and changes to uncertain tax benefits, as they relates to Fresh Start or previously completed acquisitions, occurring after January 1, 2009 will ~~change the application of fresh start accounting~~be recorded to ~~certain of the Company’s unrecognized~~income tax ~~benefits. NRG is currently evaluating the impact of this statement upon its adoption on the Company’s results of operations, financial position and cash flows.~~expense rather than additional paid-in capital or goodwill, respectively.

In ~~December 2007,~~April 2009, the FASB issued FSP No. FAS 141(R)-1Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies, or FSP FAS 141R-1, which the Company adopted effective January 1, 2009. This FSP amends and clarifies SFAS 141R,to address application issues on initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. The provisions of FSP FAS 141R-1 are applied prospectively to assets or liabilities arising from contingencies in business combinations for which the acquisition date occurs after January 1, 2009. Accordingly, the Company will apply the provisions of FSP FAS 141R-1 to the Reliant Retail acquisition.

The Company adopted SFAS No. 160,Noncontrolling Interests in Consolidated Financial ~~Statements —~~ Statements—an amendment of ARB No. 51, Consolidated Financial Statements, or SFAS ~~160.~~160, on January 1, 2009. This Statement amends ARB No. 51 to establish accounting and reporting standards for the minority interest in a subsidiary and for the deconsolidation of a subsidiary. It also amends certain of ARB No. 51’s consolidation procedures for consistency with the requirements of SFAS 141R. This Statement ~~shall be effective and~~is applied prospectively ~~for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008,~~from the date of adoption, except for the presentation and disclosure requirements, which shall be applied retrospectively. Accordingly, the Company has conformed its financial statement presentation and disclosures to the requirements of SFAS 160.

The Company adopted FSP No. APB 14-1,Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement),or FSP APB 14-1, on January 1, 2009, applying it retrospectively to all periods presented.FSP APB 14-1 clarifies that convertible debt instruments that may be settled in cash upon conversion (including partial cash settlement) do not fall within the scope of paragraph 12 of Accounting Principles Board Opinion No. 14,Accounting for Convertible Debt and Debt Issued with Stock Purchase Warrants,and specifies that issuers of such instruments should separately account for the liability component and the equity component represented by the embedded conversion option in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. Upon settlement, the entity shall allocate consideration transferred and transaction costs incurred to the extinguishment of the liability component and the reacquisition of the equity component.

During the third quarter 2006, NRG’s unrestricted wholly-owned subsidiaries CSF I and CSF II issued notes and preferred interests, or CSF Debt, which included an embedded derivative requiring NRG to pay to Credit Suisse Group, or CS, at maturity, either in cash or stock at NRG’s option, the excess of NRG’s then current stock price over a threshold price. The CSF Debt and its embedded derivative are accounted for under the guidance in FSP APB 14-1. The fair value of the embedded derivative at the date of issuance was determined to be $32 million and has been recorded as a debt discount to the CSF Debt, with a corresponding credit to Additional Paid-in Capital. This debt discount will be amortized over the terms of the underlying CSF Debt. The cumulative effect of the change in accounting principle for periods prior to December 31, 2008, was recorded as a $7 million decrease to Long-Term Debt, a $13 million decrease to Additional Paid-In Capital, and a $20 million increase to Retained Earnings on the Condensed Consolidated Balance Sheet as of December 31, 2008.

The following table summarizes the effect of the adoption of FSP APB 14-1 on income and per-share amounts for all periods presented:


	Three Months Ended March 31,
(In millions, except per share amounts)	2009			2008

Increase/(decrease):
Interest Expense	$	2		$	3
Income From Continuing Operations		(2	)		(3)
Net Income attributable to NRG Energy, Inc.		(2	)		(3)
Basic Earnings Per Share	$	—		$	(0.01	)
Diluted Earnings Per Share	$	(0.01	)	$	(0.02	)

In April 2009, the FASB issued FSP No. FAS 157-4,Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,or FSP FAS 157-4. FSP FAS 157-4 provides additional guidance for estimating fair value in accordance with FASB Statement No. 157,Fair Value Measurements, when the volume and level of activity for the asset or liability have significantly decreased and also includes guidance on identifying circumstances that indicate a transaction is ~~currently evaluating~~not orderly. This FSP applies to all assets and liabilities within the ~~impact~~scope of ~~this statement upon its~~accounting pronouncements that require or permit fair value measurements. FSP FAS 157-4 is effective for interim and annual reporting periods ending after June 15, 2009, and will be applied prospectively. Early adoption is permitted for periods ending after March 15, 2009. FSP FAS 157-4 will not have a material impact on the Company’s results of operations, financial position, ~~and~~or cash flows.

In ~~March 2008,~~April 2009, the FASB issued ~~SFAS~~FSP No. ~~161,~~FAS 107-1 and APB 28-1,Interim Disclosures about Fair Value of Financial Instruments,or FSP 107-1 and APB 28-1. This FSP amends FASB Statement No. 107,Disclosures ~~About Derivative~~about Fair Value of Financial Instruments, ~~and Hedging Activities~~~~, or SFAS 161. SFAS 161 requires entities~~ to ~~provide enhanced~~require disclosures about ~~how~~fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. This FSP also amends APB Opinion No. 28,Interim Financial Reporting, to require those disclosures in summarized financial information at interim reporting periods. This FSP applies to all financial instruments within the scope of Statement 107 held by publicly traded companies, as defined by Opinion 28. This FSP is effective for interim reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. FSP FAS 107-1 and ~~why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS No. 133,~~~~Accounting for Derivative Instruments and Hedging Activities, as amended or~~SFAS 133, and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. This statement encourages, butAPB 28-1 does not require ~~comparative~~ disclosures for earlier periods presented for comparative purposes at initial adoption. ~~SFAS 161 is effective~~In periods after initial adoption, this FSP requires comparative disclosures only for ~~financial statements issued for fiscal years and interim~~ periods ~~beginning~~ending after ~~November 15, 2008, with early application encouraged.~~initial adoption. The enhanced ~~disclosures regarding derivative and hedging instruments required by SFAS 161~~disclosure requirements are relevant to NRG but will not have an impact on the Company’s results of operations, financial position, or cash flows.

In April ~~2008,~~2009, the FASB issued FSP No. FAS 115-2 and FAS 124-2,Recognition and Presentation of Other-Than-Temporary Impairments,or FSP FAS 115-2 and FAS 124-2. This FSP amends the other-than-temporary impairment guidance in US GAAP for debt securities to make the guidance more operational and to improve the presentation and disclosure of other-than-temporary impairments on debt and equity securities in the financial statements. This FSP does not amend existing recognition and measurement guidance related to other-than-temporary impairments of equity securities. FSP FAS 115-2 and FAS 124-2 is effective for interim and annual reporting periods ending after June 15, 2009, with earlier application permitted for periods ending after March 15, 2009. This FSP does not require disclosures for earlier periods presented for comparative purposes at initial adoption. In periods after initial adoption, this FSP requires comparative disclosures only for periods ending after initial adoption. FSP FAS 115-2 and FAS 124-2 will not have a material impact on the Company’s results of operations, financial position, or cash flows.

The following accounting standards were adopted on January 1, 2009, with no impact on the Company’s results of operations, financial position, or cash flow:

	•		FSP No. FAS 142-3,Determination of the Useful Life of Intangible Assets~~, or~~
	•		FSP No. FAS ~~142-3.~~ ~~FSPFAS 142-3~~ ~~amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life~~157-2,Effective Date of ~~a recognized intangible asset under~~ FASB Statement No. 157
	•		SFAS No. ~~142,~~161,~~Goodwill~~Disclosures About Derivative Instruments and ~~Other Intangible Assets.~~Hedging Activities~~FSPFAS 142-3~~ is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years, with early adoption prohibited. NRG is currently evaluating the impact of this statement upon its adoption on the Company’s results of operations, financial position and cash flows.
	•		~~In May 2008, the FASB issued~~ FSP No. ~~APB14-1,~~FAS 132(R)-1,~~Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement)~~Employers’ Disclosures about Postretirement Benefit Plan Assets~~, or FSP APB14-1.~~ ~~FSP APB14-1~~ clarifies that convertible debt instruments that may be settled in cash upon conversion (including partial cash settlement) do not fall within the scope of paragraph 12 of Accounting Principles Board Opinion
	•		EITF No. ~~14,~~~~Accounting for Convertible Debt and Debt Issued with Stock Purchase Warrants~~, and specifies that issuers of such instruments should separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. FSP APB~~14-1~~ ~~does not apply to embedded conversion options that must be separately accounted for as derivatives under SFAS 133. FSP APB14-1~~ is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years and is to be applied retrospectively. NRG is currently evaluating the impact of this statement upon its adoption on the Company’s results of operations, financial position and cash flows. ~~In June 2008, the Emerging Issues Task Force, or EITF, issued EITFNo.~~ 07-5,Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock~~, or~~
	•		EITF ~~07-5.EITF 07-5~~ clarifies that contingent and other adjustment features in equity-linked financial instruments are consistent with equity indexation if they are based on variables that would be inputs to a “plain vanilla” option or forward pricing model and they do not increase the contract’s exposure to those variables.~~EITF 07-5~~ is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. NRG is currently evaluating the impact of this statement upon its adoption on the Company’s results of operations, financial position and cash flows. ~~In September 2008, the FASB issued FSPFAS 133-1~~ ~~andFIN 45-4,~~~~Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement~~ No. ~~133 and FASB Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161, or FSPFAS 133-1~~ ~~andFIN 45-4.~~ ~~This FSP amends FAS 133, and FIN 45~~~~Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others~~~~to require additional disclosures about credit derivatives, credit derivatives embedded in a hybrid instrument, and the current status of the payment/performance risk of a guarantee. FSPFAS 133-1~~ ~~andFIN 45-4~~ is effective for the financial statements of reporting periods (annual or interim) ending after November 15, 2008. NRG currently has no credit derivative contracts so there will be no impact on NRG related to credit derivatives. The clarification to SFAS 161 is not applicable to NRG as it only affects non-calendar year filers. The enhanced disclosures regarding the current status of the payment/performance risk of guarantees are relevant to NRG, but will not have an impact on the Company’s results of operations, financial position, or cash flows. ~~In September 2008, the EITF issuedEITF~~ 08-5,Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement
	•		EITF No. 08-6,Equity Method Investment Accounting Considerations

Note 2 — Comprehensive Income/(Loss)

The following table summarizes the components of the Company’s comprehensive income/(loss), net of tax:


(In millions)	Three months ended March 31,
	2009			2008

Net income	$	198		$	49

Changes in derivative activity		173			(302	)
Foreign currency translation adjustment		(18	)		42
Unrealized gain on available-for-sale securities		1			2

Other comprehensive income/(loss), net of tax		156			(258	)

Comprehensive income/(loss) attributable to NRG Energy, Inc.	$	354		$	(209	)

The following table summarizes the changes in the Company’s accumulated other comprehensive income, net of tax:


(In millions)

Accumulated other comprehensive income as of December 31, 2008	$	310
Changes in derivative activity		173
Foreign currency translation adjustments		(18	)
Unrealized gain on available-for-sale securities		1

Accumulated other comprehensive income as of March 31, 2009	$	466

Note 3 — Investments Accounted for by the Equity Method

MIBRAG— On February 25, 2009, NRG entered into an agreement to sell its 50% ownership interest in Mibrag B.V. to a consortium of Severočeské doly Chomutov, a member of the CEZ Group, and J&T Group. Mibrag B.V.’s principal holding is MIBRAG, which is jointly owned by NRG and URS Corporation. As part of the transaction, URS Corporation also has entered into an agreement to sell its 50% stake in MIBRAG.

For its share, NRG expects to receive EUR 202 million, subject to certain adjustments including transaction costs. The transaction is subject to customary closing conditions, including European Commission regulatory approvals and the absence of material adverse changes. NRG expects to recognize a pre-tax gain of approximately $100 million to $120 million and to close on the sale during the second quarter 2009. Prior to completion of the sale, NRG continues to record its share of MIBRAG’s operations to “Equity in earnings of unconsolidated affiliates.”

In connection with the transaction, NRG entered into a foreign currency forward contract on March 12, 2009 to hedge the impact of exchange rate fluctuations on the sale proceeds. The foreign currency forward contract has a fixed exchange rate of 1.277. The contract requires NRG to pay EUR 200 million in exchange for $255 million on June 30, 2009. For the three months ended March 31, 2009, NRG recorded an unrealized exchange loss of $9 million on the contract within “Other income/(expense), net.”

NRG will provide certain indemnities in connection with its share of the transaction. See Note 17,Guarantees,to this Form 10-Q for further discussion.

Note 4 — Fair Value of Financial Instruments

The following table presents assets and liabilities measured and recorded at fair value on the Company’s condensed consolidated balance sheet on a recurring basis and their level within the fair value hierarchy:


(In millions)	Fair Value
As of March 31, 2009	Level 1		Level 2		Level 3		Total

Cash and cash equivalents	$	1,188	$	—	$	—	$	1,188
Funds deposited by counterparties		1,275		—		—		1,275
Restricted cash		17		—		—		17
Cash collateral paid in support of energy risk management activities		178		—		—		178
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities		—		—		7		7
Marketable equity securities		2		—		—		2
Trust fund investments		157		104		27		288
Derivative assets		925		3,942		143		5,010

Total assets	$	3,742	$	4,046	$	177	$	7,965

Cash collateral received in support of energy risk management activities	$	1,277	$	—	$	—	$	1,277
Derivative liabilities		874		2,529		17		3,420

Total liabilities	$	2,151	$	2,529	$	17	$	4,697

The following table reconciles, for the three months ended March 31, 2009, the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements at least annually using significant unobservable inputs:


	Fair Value Measurement Using Significant Unobservable Inputs
		(Level 3)
(In millions)				Trust Fund
Three months ended March 31, 2009		Debt Securities		Investments			Derivatives		Total

Beginning balance as of January 1, 2009		$	7	$	31		$	49	$	87
Total gains/(losses) (realized and unrealized)
Included in earnings			—		—			19		19
Included in nuclear decommissioning obligations			—		(4	)		—		(4	)
Purchases/(sales), net			—		—			4		4
Transfer into Level 3			—		—			54		54

Ending balance as of March 31, 2009		$	7	$	27		$	126	$	160

The amount of the total gains for the period included in earnings attributable to the change in unrealized gains relating to assets still held as of March 31, 2009		$	—	$	—		$	29	$	29

Realized and unrealized gains and losses included in earnings that are related to the debt securities are recorded in other income, while those related to energy derivatives are recorded in operating revenues and cost of operations.

In determining the fair value of NRG’s Level 2 and 3 derivative contracts, NRG applies a credit reserve to reflect credit risk which is calculated based on credit default swaps. As of March 31, 2009, the credit reserve resulted in a $46 million decrease in fair value which is composed of a $23 million loss in OCI and a $23 million loss in revenue and cost of operations.

This footnote should be read in conjunction with the complete description under Note 4,Fair Value of Financial Instruments, to the Company’s financial statements in its Annual Report on Form 10-K for the year ended December 31, 2008.

Note 5 — Nuclear Decommissioning Trust Fund

The following table summarizes the fair values of the securities held in the nuclear decommissioning trust fund for the decommissioning of South Texas Project, or STP:


(In millions)	March 31, 2009		December 31, 2008

Cash and cash equivalents	$	5	$	2
US government and federal agency obligations		28		21
Federal agency mortgage-backed securities		45		49
Commercial mortgage-backed securities		14		16
Corporate debt securities		35		37
Marketable equity securities		159		178

Total	$	286	$	303

Note 6 — Accounting for Derivative Instruments and Hedging Activities

SFAS 133 requires NRG to recognize all derivative instruments on the balance sheet as either assets or liabilities and to measure them at fair value each reporting period unless they qualify for a Normal Purchase Normal Sale, or NPNS, exception. If certain conditions are met, NRG may be able to designate certain derivatives as cash flow hedges and defer the effective portion of the change in fair value of the derivatives to Other Comprehensive Income, or OCI, until the hedged transactions occur and are recognized in earnings. The ineffective portion of a cash flow hedge is immediately recognized in earnings.

For derivatives designated as hedges of the fair value of assets or liabilities, the changes in fair value of both the derivative and the hedged transaction are recorded in current earnings. The ineffective portion of a hedging derivative instrument’s change in fair value is immediately recognized into earnings.

For derivatives that are not designated as cash flow hedges or do not qualify for hedge accounting treatment, the changes in the fair value will be immediately recognized in earnings. Under the guidelines established per SFAS 133, certain derivative instruments may qualify for the NPNS exception and are therefore exempt from fair value accounting treatment. SFAS 133 applies to NRG’s energy related commodity contracts, interest rate swaps, and foreign exchange contracts.

As the Company engages principally in the trading and marketing of its generation assets, many of NRG’s commercial activities qualify for hedge accounting under the requirements of SFAS 133. In order to so qualify, the physical generation and sale of electricity should be highly probable at inception of the trade and throughout the period it is held, as is the case with the Company’s baseload plants. For this reason, many trades in support of NRG’s baseload units normally qualify for NPNS or cash flow hedge accounting treatment, and trades in support of NRG’s peaking units will generally not qualify for hedge accounting treatment, with any changes in fair value likely to be reflected on a mark-to-market basis in the statement of operations. All of NRG’s hedging and trading activities are in accordance with the Company’s risk management policy.

Energy-Related Commodities

To manage the commodity price risk associated with the Company’s competitive supply activities and the price risk associated with power sales from the Company’s electric generation facilities, NRG may enter into a variety of derivative and non-derivative hedging instruments, utilizing the following:

	•		Forward contracts, which commit NRG to sell energy commodities or~~EITF 08-5.EITF 08-5~~ requires issuers of liability instruments with third-party credit enhancements to exclude the effect of the credit enhancement when measuring the liability’s fair value. The effect of initially applying the requirements is included purchase fuels in the ~~change in~~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 ~~instrument’s fair value in~~differential between two prices for a predetermined contractual, or notional, quantity.

	•		Option contracts, which convey the ~~period of adoption. Entities are required~~right or obligation to disclose the valuation technique used to measure the liabilities and to discuss any changes in the valuation techniques used to measure those liabilities in earlier periods. Entities will also need to disclose the existence ofbuy or sell a ~~third-party credit enhancement on the entity’s issued debt.EITF 08-5~~ is effective on a prospective basis in the first reporting period beginning on or after December 15, 2008, with earlier application permitted. The fair value measurement requirements and enhanced disclosures regarding existence of third-party credit enhancements on the entity’s issued debt and valuation techniques will not have an impact on the Company’s results of operations, financial position, or cash flows.commodity.

The objectives for entering into derivative contracts designated as hedges include:

~~On October 10, 2008,~~

•

Fixing the ~~FASB issued FSPNo. FAS 157-3,~~~~Determining~~price for a portion of anticipated future electricity sales through the ~~Fair Value~~use of various derivative instruments including gas collars and swaps at a ~~Financial Asset When the Market for That Asset Is Not Active, orFSP 157-3.~~ ~~This FSP clarifies the application of SFAS 157 in a market~~level that ~~is not active and~~ provides an ~~example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active.FSP 157-3~~ is effective upon issuance, including prior periods for which financial statements have not been issued. Revisions resulting from a change in the valuation technique or its application shall be accounted for as a change in accounting estimate SFAS No. 154,~~Accounting Changes and Error Corrections~~, or SFAS 154. The disclosure provisions of SFAS 154 for a change in accounting estimate are not required for revisions resulting from a change in valuation technique or its application. Although effective for the period ended September 30, 2008,~~FSP 157-3~~ ~~did not have an impact~~acceptable return on the Company’s ~~results~~electric generation operations.

•

Fixing the price of ~~operations, financial position, or cash flows.~~

a portion of anticipated fuel purchases for the operation of NRG’s power plants.


	•	Fixing the price of a portion of anticipated energy purchases to supply NRG’s load-serving customers.
~~Note 2 —~~	~~Comprehensive Income/(Loss)~~

~~The following table summarizes the components of the Company’s comprehensive income, net of tax.~~

Three Months Ended September 30, Nine Months Ended September 30,

(In millions) 2008 2007 2008 2007

Net income $ 784 $ 268 $ 965 $ 482

Changes in derivative activity 1,112 46 112 (278 )
Foreign currency translation adjustment (104 ) 39 (54 ) 65
Unrealized gain/(loss) on available-for-sale securities (4 ) — (1 ) 1

Other comprehensive income/(loss), net of tax $ 1,004 $ 85 $ 57 $ (212 )

Comprehensive income $ 1,788 $ 353 $ 1,022 $ 270

~~The following table summarizes the changes in the Company’s accumulated other comprehensive loss, net of tax.~~

(In millions)

As of September 30, 2008

Accumulated other comprehensive loss as of December 31, 2007 $ (115 )
Changes in derivative activity 112
Foreign currency translation adjustments (54 )
Unrealized loss on available-for-sale securities (1 )

Accumulated other comprehensive loss as of September 30, 2008 $ (58 )

NRG’s trading activities include contracts entered into to profit from market price changes as opposed to hedging an exposure, and are subject to limits in accordance with the Company’s risk management policy. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings. These trading activities are a complement to NRG’s energy marketing portfolio.

Interest Rate Swaps

NRG is exposed to changes in interest rates through the Company’s issuance of variable and fixed rate debt. In order to manage the Company’s interest rate risk, NRG enters into interest-rate swap agreements. As of March 31, 2009, NRG had interest rate derivative instruments extending through June 2019, all of which had been designated as either cash flow or fair value hedges.

Volumetric Underlying Derivative Transactions

The following table summarizes the net notional volume buy/(sell) of NRG’s derivative transactions broken out by commodity with the exception of those that qualified for the NPNS exception as of March 31, 2009. Option contracts are reflected using delta volume. Delta volume equals the notional volume of an option adjusted for the probability that the option will be in the money at its expiration date.


		Total Volume
Commodity	Units	(In millions)

Emissions	Short Ton		2
Coal	Short Ton		62
Natural Gas	MMBtu		(797	)
Oil	Barrel		1
Power	MWH		(99	)
Interest	Dollars	$	2,419

Fair Value of Derivative Instruments

The following table summarizes the fair value within the derivative instrument valuation on the balance sheet as of March 31, 2009:


	Fair Value
(In millions)		Derivatives Asset		Derivatives Liability

Derivatives Designated as Cash Flow or Fair Value Hedges:
Interest rate contracts current		$	—		$ 6
Interest rate contracts long term			15		135
Commodity contracts current			414		3
Commodity contracts long term			473		20

Total Derivatives Designated as Cash Flow or Fair Value Hedges			902		164


Derivatives Not Designated as Cash Flow or Fair Value Hedges:
Commodity contracts current			3,448		2,982
Commodity contracts long term			660		265
Foreign currency current			—		9

Total Derivatives Not Designated as Cash Flow or Fair Value Hedges			4,108		3,256

Total Derivatives			$ 5,010		$ 3,420

Impact of Derivative Instruments on the Statement of Financial Performance

The following table summarizes the amount of gain/(loss) resulting from fair value hedges reflected in interest income/(expense) for interest rate contracts:


(In millions)	Amount of gain/(loss)
Three months ended March 31, 2009	recognized

Derivative	$	(1	)
Senior Notes (hedged item)	$	1

The following table summarizes the location and amount of gain/(loss) resulting from cash flow hedges:

Amount of

Location of

Amount of

Location of

Amount of

gain/(loss)

recognized in OCI

reclassified from

recognized in

(In millions)

(effective portion)

Accumulated

income

Three months ended March 31, 2009

after tax

OCI into Income

(ineffective portion)

Interest rate contracts

Interest expense

)

Interest expense

—

Commodity contracts

161

Operating
revenue

112

Operating revenue

Total

173

111

The following table summarizes the amount of gain/(loss) recognized in income for derivatives not designated as cash flow or fair value hedges on commodity contracts:


	Amount of
	gain/(loss)
	recognized in
	income or cost of
(In millions)	operations for
Three months ended March 31, 2009	derivatives

Location of gain/(loss) recognized in income for derivatives:
Operating revenue	$	323
Cost of operations	$	(52	)

Credit Risk Related Contingent Features

Certain of the Company’s hedging agreements contain provisions that require the Company to post additional collateral if the counterparty determines that there has been deterioration in credit quality, generally termed ‘adequate assurance’ under the agreements. While deterioration in credit quality is not defined, it could generally be interpreted to mean at least a three notch downgrade from existing credit ratings. Other agreements contain provisions that require the Company to post additional collateral if there was a one notch downgrade in the Company’s credit rating. The aggregate fair value of all derivative instruments that have adequate assurance clauses that are in a net liability position as of March 31, 2009 was $21 million. The aggregate fair value of all derivative instruments with credit rating contingent features that are in a net liability position as of March 31, 2009 was $37 million. In addition, there are certain marginable agreements where NRG has a net liability position but the counterparty has not called for the collateral due, which is approximately $95 million.

Concentration of Credit Risk

Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. The Company monitors and manages credit risk through credit policies that include: (i) an established credit approval process, (ii) a daily monitoring of counterparties’ credit limits, (iii) the use of credit mitigation measures such as margin, collateral, credit derivatives or prepayment arrangements, (iv) the use of payment netting agreements, and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty. Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. The Company seeks to mitigate counterparty risk with a diversified portfolio of counterparties, including ten participants under its first and second lien structure. The Company also has credit protection within various agreements to call on additional collateral support if and when necessary. Cash margin is collected and held at NRG to cover the credit risk of the counterparty until positions settle.

Under the current economic downturn in the US and overseas, the Company has heightened its management and mitigation of counterparty credit risk by using credit limits, netting agreements, collateral thresholds, volumetric limits and other mitigation measures, where available. NRG avoids concentration of counterparties whenever possible and applies credit policies that include an evaluation of counterparties’ financial condition, collateral requirements and the use of standard agreements that allow for netting and other security.

As of March 31, 2009, total credit exposure to substantially all counterparties was $2.6 billion and NRG held collateral (cash and letters of credit) against those positions of $1.3 billion resulting in a net exposure of $1.3 billion. Total credit exposure is discounted at a risk free rate.

The following table highlights the credit quality and the net counterparty credit exposure by industry sector. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market and NPNS and non-derivative transactions. The exposure is shown net of collateral held, and includes amounts net of receivables or payables.


		Net Exposure_(a)

~~Note 3 —~~	~~Discontinued Operations~~

NRG has classified material business operations and gains/losses recognized on sale as discontinued operations for projects that were sold or have met the required criteria for such classification. The financial results for the affected businesses have been accounted for as discontinued operations.

~~The assets and liabilities reported in the balance sheet~~ as of ~~December~~March 31, ~~2007 as discontinued operations represent those~~2009

Category

(% of Itiquira Energetica S.A., or ITISA. On April 28, 2008, NRG completed the sale of its 100% interest in Tosli Acquisition B.V., or Tosli, which held all NRG’s interest in ITISA, to Brookfield Renewable Power Inc. (previously Brookfield Power Inc.), a wholly-owned subsidiary of Brookfield Asset Management Inc. In addition, the purchase price adjustment contingency under the sale agreement was resolved on August 7, 2008. In connection with the sale, NRG received $300 million of cash proceeds from Brookfield,Total)

Coal suppliers

Financial institutions

Utilities, energy, merchants, marketers and removed $163 million of assets, including $59 million of cash, $122 million of liabilities, including $63 million of debt, and $15 million in foreign currency translation adjustment from its 2008 condensed consolidated balance sheet.

~~Summarized operating results for the Company’s discontinued operations, consisting of ITISA’s activities, were as follows:~~

Three months ended September 30, Nine months ended September 30,

(In millions) 2008 2007 2008 2007

Operating revenues $ — $ 13 $ 20 $ 36
Operating costs and other expenses — 7 9 18

Pre-tax income from operations of discontinued components — 6 11 18
Income tax expense — 3 3 5

Income from operations of discontinued components — 3 8 13

Disposal of discontinued components — pre-tax gain 3 — 273 —
Income tax expense 3 — 109 —

Gain on disposal of discontinued components, net of income tax — — 164 —

Income from discontinued operations, net of income tax expense $ — $ 3 $ 172 $ 13


~~Note 4 —~~	~~Fair Value of Financial Instruments~~other			32

~~Fair Value of Long-Term Debt~~

The Company’s long-term debt is recorded at carrying value on the Company’s consolidated balance sheet. The carrying amounts and fair value of the Company’s long-term debt as of September 30, 2008 and December 31, 2007 were as follows:

September 30, 2008 December 31, 2007

Carrying
Fair
Carrying
Fair

(In millions)
Amount Value Amount Value

Long-term debt, including current portion $ 8,028 $ 7,218 $ 8,180 $ 8,164

The fair value of long-term debt is based on quoted market prices for these instruments that are publicly traded, or estimated based on the income approach valuation technique for non-publicly traded debt using current interest rates for similar instruments with equivalent credit quality.

~~Adoption of SFAS No. 157~~

The Company partially adopted SFAS 157 on January 1, 2008, delaying application for non-financial assets and non-financial liabilities as permitted. This statement establishes a framework for measuring fair value, and expands disclosures about fair value measurements.

~~SFAS 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:~~


	•	~~Level 1~~ — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Company has the ability to access as of the measurement date. NRG’s financial assets and liabilities utilizing Level 1 inputs include active exchange-traded securities, energy derivatives, and trust fund investments.
ISOs			3

Total			100	%

	•	~~Level 2~~ — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data. NRG’s financial assets and liabilities utilizing Level 2 inputs include fixed income securities, exchange-based derivatives, and over-the-counter derivatives such as swaps, options and forwards.


	Net Exposure_(a)
	as of March 31, 2009
Category	(% of Total)

Investment grade		95	%
Non-investment grade		1
Non-rated		4

Total		100	%

•

~~Level 3~~ — unobservable inputs for the asset or liability only used when there is little, if any, market activity for the asset or liability at the measurement date. NRG’s financial assets and liabilities utilizing Level 3 inputs include infrequently-traded, non-exchange-based derivatives and commingled investment funds, and are measured using present value pricing models.

In accordance with SFAS 157, the Company determines the level in the fair value hierarchy within which each fair value measurement in its entirety falls, based on the lowest level input that is significant to the fair value measurement in its entirety.

~~Recurring Fair Value Measurements~~

~~The following table presents assets~~

(a)

Credit exposure excludes California tolling, uranium, coal transportation/railcar leases, New England Reliability-Must-Run, cooperative load contracts and ~~liabilities measured and recorded at fair value on the Company’s consolidated balance sheet on a recurring basis and their level within the fair value hierarchy as of September 30, 2008:~~

(In millions)
Fair Value
As of September 30, 2008 Level 1 Level 2 Level 3 Total

Investment in available-for-sale securities (classified within other non-current assets):
Debt securities $ — $ — $ 10 $ 10
Marketable equity securities 5 — — 5
Trust fund investments 180 135 20 335
Derivative assets 2,152 2,832 22 5,006

Total assets $ 2,337 $ 2,967 $ 52 $ 5,356

Derivative liabilities $ 2,153 $ 3,023 $ 4 $ 5,180

The following table reconciles, for the period ended September 30, 2008, the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements at least annually using significant unobservable inputs:

Fair Value Measurement Using Significant Unobservable Inputs
(Level 3)
(In millions)
Trust Fund

Nine Months Ended September 30, 2008 Debt Securities Investments Derivatives Total

Beginning balance as of January 1, 2008 $ 32 $ 37 $ 27 $ 96
Total gains and losses (realized/unrealized)
Included in earnings (22 ) — (19 ) (41 )
Included in nuclear decommissioning obligations — (9 ) — (9 )
Included in other comprehensive income — — 28 28
Purchases/(sales), net — (9 ) (17 ) (26 )
Transfer into Level 3 — 1 (1 ) —

Ending balance as of September 30, 2008
$ 10 $ 20 $ 18 $ 48

The amount of the total gains or losses for the period included in earnings attributable to the change in unrealized gains and losses relating to assets still held as of September 30, 2008 $ 22 $ — $ 19 $ 41

~~Non-derivative fair value measurements~~

~~NRG’s debt securities are classified as Level 3 and consist of non-traded debt instruments that are valued based on an auction process.~~

The trust fund investments are held primarily to satisfy NRG’s nuclear decommissioning obligations. These trust fund investments hold debt and equity securities directly and equity securities indirectly through commingled funds. The fair values of equity securities held directly by the trust funds are based on quoted prices in active markets and are categorized in Level 1. In addition, US Treasury securities are categorized as Level 1 because they trade in a highly liquid and transparent market. The fair values of fixed income securities, excluding US Treasury securities, are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized in Level 2. Commingled funds, which are analogous to mutual funds, are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives. The fair value of commingled funds are based on net asset values per fund share (the unit of account), derived from the quoted prices in active markets of the underlying equity securities. However, because the shares in the commingled funds are not publicly quoted, not traded in an active market and are subject to certain restrictions regarding their purchase and sale, the commingled funds are categorized in Level 3. See Note 5~~Nuclear Decommissioning Trust Fund.~~

~~Derivative fair value measurements~~

A small portion of NRG’s contracts are exchange-traded contracts with readily available quoted market prices. The majority of NRG’s contracts are non exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter, on-line exchanges. For the majority of our markets we receive quotes from multiple sources. To the extent that we receive multiple quotes our prices reflect the average of the bid-ask mid-point prices obtained from all sources that NRG believes provide the most liquid market for the commodity. If we only receive one quote then the mid-point of the bid-ask spread for that quote is used. The terms for which such price information is available vary by commodity, region and product. The remainder of the assets and liabilities represent contracts for which external sources or observable market quotes are not available. These contracts are valued based on various valuation techniques including but not limited to internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Contracts valued with prices provided by models and other valuation techniques make up 11% of the total fair value of all derivativeTexas Westmoreland coal contracts. The fair value of each contract is discounted using a risk free interest rate. In addition, we apply a credit reserve to reflect credit risk which is calculated based on published default probabilities. To the extent that our net exposure under a specific master agreement is an asset we are using the counterparty’s risk of default. If the exposure under a specific master agreement is a liability we are using NRG’s probability of default. The credit reserve is added to the discounted fair value to reflect the exit price that a market participant would be willing to receive to assume NRG’s liabilities or that a market participant would be willing to pay for NRG’s assets. As of September 30, 2008 the credit reserve resulted in a $6 million decrease in fair value which is composed of a $5 million gain in OCI and an $11 million loss in derivative revenue. The fair values in each category reflect the level of forward prices and volatility factors as of September 30, 2008 and may change as a result of changes in these factors. Management uses its best estimates to determine the fair value of commodity and derivative contracts NRG holds and sells. These estimates consider various factors including closing exchange and over-the-counter price quotations, time value, volatility factors and credit exposure. It is possible, however, that future market prices could vary from those used in recording assets and liabilities from energy marketing and trading activities and such variations could be material.

NRG has credit risk exposure to certain counterparties representing more than 10% of total net exposure and the aggregate of such counterparties was $444 million. No single counterparty represents more than 19% of total net credit exposure. Approximately 85% of NRG’s positions relating to credit risk roll-off by the end of 2011. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration. Given the credit quality, diversification and term of the exposure in the portfolio, NRG does not anticipate a material impact on the Company’s financial results from nonperformance by a counterparty.

Accumulated Other Comprehensive Income

The following table summarizes the effects of SFAS 133 on NRG’s accumulated OCI balance attributable to hedged derivatives, net of tax:


(In millions)	Energy			Interest
Three months ended March 31, 2009	Commodities			Rate			Total

Accumulated OCI balance at December 31, 2008	$	406		$	(91	)	$	315
Realized from OCI during the period:
— Due to realization of previously deferred amounts		(112	)		1			(111	)
— Due to discontinuance of cash flow hedge accounting		(133	)		—			(133	)
Mark-to-market of cash flow hedge accounting contracts		406			11			417

Accumulated OCI balance at March 31, 2009	$	567		$	(79	)	$	488

Gains/(losses) expected to be realized from OCI during the next 12 months, net of $180 tax	$	287		$	(4	)	$	283

~~Under the guidance of FSPFIN 39-1,~~ entities may choose to offset derivative positions in the financial statements against the fair value of the amounts recognized as cash collateral paid or received under those arrangements. The Company has credit arrangements within various agreements to call on or pay additional collateral support. The Company has chosen not to offset positions as defined in this FSP. As of September 30, 2008, the Company recorded $544 million of cash collateral paid and $154 million of cash collateral received on its balance sheet.

NRG’s nuclear decommissioning trust fund assets which are for the decommissioning of South Texas Project, or STP, are primarily comprised of securities recorded at fair value based on actively quoted market prices. NRG accounts for these trust fund assets per SFAS 71,~~Accounting for the Effects of Certain Types of Regulation~~, because the Company’s nuclear decommissioning activities are regulated by the Public Utility Commission of Texas, or PUCT. Although the owners of STP are responsible for the management of decommissioning STP, the cost of decommissioning is the responsibility of the Texas ratepayers. As such, NRG does not bear the cost for these decommissioning responsibilities, except to the extent that NRG has a prudence obligation with respect to the management of the trust funds and the future decommissioning of STP. Third party appraisals are periodically conducted to estimate the future decommissioning liability related to STP. These appraisals are then used to determine the adequacy of the existing decommissioning trust investments to cover that estimated future liability. Should there be a shortfall in the value of the assets in the trust relative to the estimated liability, NRG has the ability to file a rate case with the PUCT to increase decommissioning reimbursements over time from retail customers.

~~The following table summarizes the fair values of the securities held in the trust funds as of September 30, 2008 and December 31, 2007:~~

SFAS 133, requires NRG to recognize all derivative instruments on the balance sheet as either assets or liabilities and to measure them at fair value each reporting period unless they qualify for a Normal Purchase Normal Sale, or NPNS, exception. If certain conditions are met, NRG may be able to designate certain derivatives as cash flow hedges and defer the effective portion of the change in fair value of the derivatives to Other Comprehensive Income, or OCI, until the hedged transactions occur and are recognized in earnings. The ineffective portion of a cash flow hedge is immediately recognized in earnings.

~~Accumulated Other Comprehensive Income~~

~~The following tables summarize the effects of SFAS 133 on NRG’s OCI balance attributable to hedged derivatives, net of tax:~~

(In millions)
Energy
Interest

Three months ended September 30, 2007 Commodities Rate Total

Accumulated OCI balance at June 30, 2007 $ (145 ) $ 30 $ (115 )
Realized from OCI during the period:
— Due to realization of previously deferred amounts (10 ) (1 ) (11 )
Mark-to-market of hedge contracts 86 (29 ) 57

Accumulated OCI balance at September 30, 2007 $ (69 ) $ — $ (69 )

(In millions)
Energy
Interest

Nine months ended September 30, 2008 Commodities Rate Total

Accumulated OCI balance at December 31, 2007 $ (234 ) $ (31 ) $ (265 )
Realized from OCI during the period:
— Due to realization of previously deferred amounts 32 — 32
Mark-to-market of hedge contracts 81 (1 ) 80

Accumulated OCI balance at September 30, 2008 $ (121 ) $ (32 ) $ (153 )

(In millions)
Energy
Interest

Nine months ended September 30, 2007 Commodities Rate Total

Accumulated OCI balance at December 31, 2006 $ 193 $ 16 $ 209
Realized from OCI during the period:
— Due to realization of previously deferred amounts (37 ) (1 ) (38 )
Mark-to-market of hedge contracts (225 ) (15 ) (240 )

Accumulated OCI balance at September 30, 2007 $ (69 ) $ — $ (69 )

As of September 30, 2008 and 2007, the net balances in OCI relating to SFAS 133 were unrecognized losses of approximately $153 million and $69 million, which were net of income taxes of $102 million and $46 million, respectively.

As of July 31, 2008, our regression analysis for natural gas prices to ERCOT power prices did not meet the required threshold for cash flow hedge accounting for calendar years 2012 and 2013. As a result, we de-designated our 2012 and 2013 ERCOT cash flow hedges as of July 31, 2008. We will continue to monitor the correlations in this market, and if the regression analysis meets the required thresholds in the future, we may elect to re-designate these transactions as cash flow hedges.

~~Statement of Operations~~

In accordance with SFAS 133, unrealized gains and losses associated with changes in the fair value of derivative instruments not accounted for as hedge derivatives and ineffectiveness of hedge derivatives are reflected in current period earnings.

The following table summarizes the pre-tax effects of economic hedges that did not qualify for cash flow hedge accounting, ineffectiveness on cash flow hedges, and trading activity on NRG’s statement of operations. These amounts are included within operating revenues.

Three months ended September 30, Nine months ended September 30,

(In millions) 2008 2007 2008 2007

Unrealized mark-to-market results

Reversal of previously recognized unrealized gains on settled positions related to economic hedges $ (7 ) $ (17 ) $ (32 ) $ (109 )
Reversal of previously recognized unrealized gains on settled positions related to trading activity (9 ) (3 ) (20 ) (23 )
Net unrealized gains on open positions related to economic hedges 439 1 180 22
(Loss)/gain on ineffectiveness associated with open positions treated as cash flow hedges 352 9 (27 ) 32
Net unrealized gains on open positions related to trading activity 26 16 57 37

Total unrealized mark-to-market results
$ 801 $ 6 $ 158 $ (41 )

~~Discontinued Hedge Accounting~~ — During the third quarter of 2008, a relatively mild summer season in the Northeast resulted in falling power prices and expected lower power generation for the remainder of 2008 and calendar year 2009. As such, NRG discontinued cash flow hedge accounting for certain contracts related to commodity price risk previously accounted for as cash flow hedges for 2008 and 2009. These contracts were originally entered into as hedges of forecasted sales by baseload plants. As a result, $31 million of gain previously deferred in OCI was recognized in earnings for the three and nine months ended September 30, 2008.


(In millions)	Energy			Interest
Three months ended March 31, 2008	Commodities			Rate			Total

Accumulated OCI balance at December 31, 2007	$	(234	)	$	(31	)	$	(265	)
Realized from OCI during the period:
— Due to realization of previously deferred amounts		(15	)		—			(15	)
Mark-to-market of cash flow hedge accounting contracts		(244	)		(43	)		(287	)

Accumulated OCI balance at March 31, 2008	$	(493	)	$	(74	)	$	(567	)

Losses expected to be realized from OCI during the next 12 months, net of $69 tax	$	(104	)	$	(2	)	$	(106	)

As of March 31, 2009, the net balance in OCI relating to SFAS 133 was an unrecognized gain of approximately $488 million, which is net of $305 million in income taxes. As of March 31, 2008, the net balance in OCI relating to SFAS 133 was unrecognized losses of approximately $567 million, which was net of $371 million in income taxes.

As of July 31, 2008, the Company’s regression analysis for natural gas prices to ERCOT power prices while positively correlated did not meet the required threshold for cash flow hedge accounting for calendar years 2012 and 2013. As a result, the Company de-designated its 2012 and 2013 ERCOT cash flow hedges as of July 31, 2008 and prospectively mark these derivatives to market. The Company will continue to monitor the correlations in this market, and if the regression analysis meets the required thresholds in the future, the Company may elect to re-designate these transactions as cash flow hedges.

Statement of Operations

In accordance with SFAS 133, unrealized gains and losses associated with changes in the fair value of derivative instruments not accounted for as cash flow hedge derivatives and ineffectiveness of hedge derivatives are reflected in current period earnings.


	Three Months Ended March 31,
(In millions)		2009			2008

Unrealized mark-to-market results
Reversal of previously recognized unrealized gains on settled positions related to economic hedges		$	(16	)	$	(10	)
Reversal of previously recognized unrealized gains on settled positions related to trading activity			(69	)		(5	)
Net unrealized gains/(losses) on open positions related to economic hedges			349			(97	)
Gains/(losses) on ineffectiveness associated with open positions treated as cash flow hedges			4			(45	)
Net unrealized gains on open positions related to trading activity			7			16

Total unrealized gains/(losses)		$	275		$	(141	)


	Three months ended March 31,
(In millions)	2009			2008

Revenue from operations — energy commodities	$	327		$	(141	)
Cost of operations		(52	)		—

Total impact to statement of operations	$	275		$	(141	)

For the three months ended March 31, 2009, the unrealized gain associated with changes in the fair value of derivative instruments not accounted for as hedge derivatives of $275 million was comprised of $349 million of fair value increases in forward sales of electricity and fuel, $4 million of ineffectiveness, $85 million loss from the reversal of mark-to-market gains, which ultimately settled as financial revenues, and $7 million of gains associated with the Company’s trading activity. The $349 million gain from economic hedge positions includes $217 million recognized in earnings from previously deferred amounts in OCI as the Company discontinued cash flow hedge accounting for certain 2009 transactions in Texas and New York due to lower expected generation, and $132 million of increase in value of forward sales of electricity and fuel due to forward power and gas prices. The $4 million gain is primarily from hedge accounting ineffectiveness related to gas trades in Texas which was driven by decreasing forward gas prices while forward power prices decreased at a slower pace. The Company recognized a derivative loss of $29 million resulting from discontinued NPNS designated coal purchases due to expected lower coal consumption and accordingly could not assert taking physical delivery of coal purchase transaction under NPNS designation. This amount is included in the Company’s cost of operations.


~~Note 7 — Long-Term Debt~~

~~Debt Related to NRG Common Stock Finance I, LLC~~

In March 2008, the Company executed an arrangement with Credit Suisse, or CS, to extend the notes and preferred interest maturities of NRG Common Stock Finance I, LLC, or CSF I, from October 2008 to June 2010. In addition, the settlement date of an embedded derivative, or CSFI CAGR, which is based on NRG’s share price appreciation beyond a 20% compound annual growth rate since the original date of purchase by CSF I, was extended 30 days to early December 2008. As part of this extension arrangement, the Company contributed 795,503 treasury shares to CSF I as additional collateral to maintain a blended interest rate in the CSF I facility of approximately 7.5%. Accordingly, the amount due at maturity in June 2010 for the CSF I notes and preferred interests will be $248 million.

In August 2008, the Company amended the CSF I notes and preferred interests to early settle the CSFI CAGR. Accordingly, NRG made a cash payment of $45 million to CS for the benefit of CSFI, which was recorded to interest expense in the Company’s Consolidated Statement of Operations.

~~Senior Credit Facility~~

Beginning in 2008, NRG must annually offer a portion of its excess cash flow (as defined in the Senior Credit Facility) for the prior year to its first lien lenders under the Company’s Term B loan. The percentage of the excess cash flow offered to these lenders is dependent upon the Company’s consolidated leverage ratio (as defined in the Senior Credit Facility) at the end of the preceding year. Of the amount offered, the first lien lenders must accept 50%, while the remaining 50% may either be accepted or rejected at the lenders’ option. The mandatory annual offer required for 2008 was $446 million, against which the Company made a prepayment of $300 million in December 2007. Of the remaining $146 million, the lenders accepted a repayment of $143 million in March 2008. The amount retained by the Company can be used for investments, capital expenditures and other items as permitted by the Senior Credit Facility.


~~Note 8 —~~	~~Changes in Capital Structure~~

~~The following table reflects the changes in NRG’s common stock issued and outstanding during the nine months ended September 30, 2008:~~

Authorized Issued Treasury Outstanding

Balance as of December 31, 2007
500,000,000 261,285,529 (24,550,600 ) 236,734,929
2008 Capital Allocation Program — — (4,691,883 ) (4,691,883 )
Shares issued from LTIP — 984,176 — 984,176

Balance as of September 30, 2008
500,000,000 262,269,705 (29,242,483 ) 233,027,222

~~Treasury Stock~~

In December 2007, the Company initiated its 2008 Capital Allocation Program, with the repurchase of 2,037,700 shares of NRG common stock during that month for approximately $85 million. In February 2008, the Company’s Board of Directors authorized an additional $200 million in common share repurchases that would raise the total 2008 Capital Allocation Program to approximately $300 million. In the first quarter 2008, the Company repurchased 1,281,600 shares of NRG common stock for approximately $55 million. In the third quarter 2008, the Company repurchased an additional 3,410,283 of NRG common stock in the open market for approximately $130 million. As of September 30, 2008, NRG had repurchased a total of 6,729,583 shares of NRG common stock at a cost of approximately $270 million as part of its 2008 Capital Allocation Program.

For the three months ended March 31, 2008, the unrealized loss associated with changes in the fair value of derivative instruments not accounted for as hedge derivatives of $141 million was comprised of $97 million of fair value decreases in forward sales of electricity and fuel, a $45 million loss due to the ineffectiveness associated with financial forward contracted electric and gas sales, $15 million from the reversal of mark-to-market gains which ultimately settled as financial revenues of which $10 million was related to economic hedges and $5 million was related to trading activity. These decreases were partially offset by $16 million of gains associated with open positions related to trading activity.

Discontinued Hedge Accounting— During the first quarter 2009, a relatively sharp decline in commodity prices resulted in falling power prices and expected lower power generation for the remainder of 2009. As such, NRG discontinued cash flow hedge accounting for certain 2009 contracts previously accounted for as cash flow hedges. These contracts were originally entered into as hedges of forecasted sales by baseload plants in Texas and Northeast. As a result, $217 million of gain previously deferred in OCI was recognized in earnings for the three months ended March 31, 2009.

Discontinued Normal Purchase and Sale for Coal Purchase –Due to the decline in commodity prices, the Company’s coal consumption is lower than forecasted, and the Company expects to build-up inventory due to anticipated lower baseload plant generation. The Company may need to net settle some of its coal purchases under NPNS designation and thus would no longer be able to assert physical delivery under these coal contracts. The forward positions previously treated as accrual accounting have been reclassified into mark-to-market accounting during the quarter and prospectively. The impact of discontinuance of coal NPNS designated transactions resulted in a derivative loss of $29 million and reflected in cost of operations for the three months ended March 31, 2009.

Note 7 — Long-Term Debt

Senior Credit Facility

In March 2009, NRG made a repayment of approximately $197 million to its first lien lenders under the Term Loan Facility. This payment resulted from the mandatory annual offer of a portion of NRG’s excess cash flow (as defined in the Senior Credit Facility) for the prior year.

TANE Facility

On February 24, 2009, Nuclear Innovation North America LLC, or NINA, executed an Engineering, Procurement and Construction, or EPC, agreement with Toshiba American Nuclear Energy Corporation, or TANE, which specifies the terms under which STP Units 3 and 4 will be constructed. Concurrent with the execution of the EPC agreement, NINA and TANE entered into a credit facility, or the TANE Facility, wherein TANE has committed up to $500 million to finance purchases of long-lead materials and equipment for the construction of STP 3 and 4. The TANE Facility matures on February 24, 2012, subject to two renewal periods, and provides for customary events of default, which include, among others: nonpayment of principal or interest; default under other indebtedness; the rendering of judgments; and certain events of bankruptcy or insolvency. Outstanding borrowings will accrue interest at LIBOR plus 3%, subject to a ratings grid, and are secured by substantially all of the assets of and membership interests in NINA and its subsidiaries. As of March 31, 2009, no amounts have been borrowed under the TANE Facility. NINA will be required to repay all outstanding amounts associated with its existing $20 million revolving credit facility before borrowing under the TANE Facility.

Debt Related to Capital Allocation Program

Share Lending Agreements— On February 20, 2009, CSF I and CSF II, wholly-owned unrestricted subsidiaries of the Company, entered into Share Lending Agreements with affiliates of Credit Suisse Group, or CS, relating to the shares of NRG common stock currently held by CSF I and II in connection with the CSF I and CSF II issued notes and preferred interests agreements, or CSF Debt, originally entered into on August 4, 2006, by and between CSF I and II and affiliates of CS. The Company entered into Share Lending Agreements due to the current lack of liquidity in the stock borrow market for NRG shares and in order to maintain the intended economic benefits of the CSF Debt agreements. As of March 31, 2009 CSF I and II have lent affiliates of CS 12,000,000 shares of the 21,970,903 shares of NRG common stock held by CSF I and II. The Share Lending Agreements permit affiliates of CS to borrow up to the total number of shares of NRG common stock held by CSF I and II.

Shares borrowed by affiliates of CS under the Share Lending Agreement will be used to replace shares borrowed by affiliates of CS from third parties in connection with CS’ hedging activities related to the financing agreements.


~~Note 9 —~~	~~Equity Compensation~~

~~Non-Qualified Stock Options, or NQSO’s~~

~~The following table summarizes the Company’s NQSO activity as of September 30, 2008 and the changes during the nine months then ended:~~

Aggregate

Weighted
Intrinsic

Average
Value

Shares Exercise Price (In millions)

Outstanding as of December 31, 2007
3,579,775 $ 19.98
Granted 1,174,200 40.48
Forfeited (148,536 ) 32.79
Exercised (507,986 ) 16.29

Outstanding at September 30, 2008
4,097,453 25.84 $ —
Exercisable at September 30, 2008
2,056,803 $ 17.54 15

~~The weighted average grant date fair value of NQSO’s granted for the nine months ending September 30, 2008 was $10.61.~~

~~Restricted Stock Units, or RSU’s~~

~~The following table summarizes the Company’s non-vested RSU awards as of September 30, 2008 and changes during the nine months then ended:~~

Weighted

Average

Grant-Date

Fair Value

Units Per Unit

Non-vested as of December 31, 2007
1,588,316 $ 26.99
Granted 163,200 40.22
Vested (610,760 ) 19.38
Forfeited (71,320 ) 31.13

Non-vested as of September 30, 2008
1,069,436 $ 33.08

~~Performance Units, or PU’s~~

~~The following table summarizes the Company’s non-vested PU awards as of September 30, 2008 and changes during the nine months then ended:~~

Weighted

Average

Grant- Date

Fair Value

Units Per Unit

Non-vested as of December 31, 2007
536,764 $ 20.18
Granted 227,300 27.75
Vested (50,000 ) 15.74
Forfeited (59,700 ) 21.49

Non-vested as of September 30, 2008
654,364 $ 23.05

~~In the third quarter 2008, 100,000 shares of common stock were issued for performance units that vested in accordance with the plan payout provisions.~~

~~Employee Stock Purchase Plan~~

In May 2008, NRG shareholders approved the adoption of the NRG Energy, Inc. Employee Stock Purchase Plan, or ESPP, pursuant to which eligible employees may elect to withhold up to 10% of their eligible compensation to purchase shares of NRG common stock at 85% of its fair market value on the exercise date. An exercise date occurs each June 30 and December 31. The initial six month employee withholding period began July 1, 2008 and ends December 31, 2008. There are 500,000 shares of treasury stock reserved for issuance under the ESPP.


~~Note 10 —~~	~~Earnings Per Share~~

Basic earnings per common share is computed by dividing net income adjusted for accumulated preferred stock dividends by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the year are weighted for the portion of the year that they were outstanding. Diluted earnings per share is computed in a manner consistent with that of basic earnings per share while giving effect to all potentially dilutive common shares that were outstanding during the period.

~~The reconciliation of basic earnings per common share to diluted earnings per share is as follows:~~

Three months ended
September 30, Nine months ended
September 30,
(In millions, except per share data) 2008 2007 2008 2007

Basic earnings per share

Numerator:

Income from continuing operations $ 784 $ 265 $ 793 $ 469
Preferred stock dividends (13 ) (13 ) (41 ) (41 )

Net income available to common stockholders from continuing operations 771 252 752 428
Discontinued operations, net of income tax expense — 3 172 13

Net income available to common stockholders $ 771 $ 255 $ 924 $ 441

Denominator:

Weighted average number of common shares outstanding 234.8 239.4 235.7 240.5
Basic earnings per share:

Income from continuing operations $ 3.28 $ 1.05 $ 3.19 $ 1.78
Discontinued operations, net of income tax expense — 0.02 0.73 0.05

Net income $ 3.28 $ 1.07 $ 3.92 $ 1.83

Diluted earnings per share

Numerator:

Net income available to common stockholders from continuing operations $ 771 $ 252 $ 752 $ 428
Add preferred stock dividends for dilutive preferred stock 11 11 34 34

Adjusted income from continuing operations available to common shareholders 782 263 786 462
Discontinued operations, net of tax — 3 172 13

Net income available to common stockholders $ 782 $ 266 $ 958 $ 475

Denominator:

Weighted average number of common shares outstanding 234.8 239.4 235.7 240.5
Incremental shares attributable to the issuance of equity compensation (treasury stock method) 2.2 3.8 3.0 3.7
Incremental shares attributable to embedded derivatives of certain financial instruments (if-converted method) 2.0 4.6 1.8 4.9
Incremental shares attributable to assumed conversion features of outstanding preferred stock (if-converted method) 37.5 37.5 37.5 37.5

Total dilutive shares 276.5 285.3 278.0 286.6
Diluted earnings per share:

Income from continuing operations available to common shareholders $ 2.83 $ 0.92 $ 2.83 $ 1.61
Income from discontinued operations, net of tax — 0.01 0.62 0.05

Net income $ 2.83 $ 0.93 $ 3.45 $ 1.66

~~Effects on Earnings per Share~~

~~The following table summarizes NRG’s outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company’s diluted earnings per share:~~

Three Months Ended September 30, Nine Months Ended September 30,
(In millions of shares) 2008 2007 2008 2007

Equity compensation 1.8 — 1.4 0.4
Embedded derivative of 3.625% convertible perpetual preferred stock 14.0 13.2 14.2 13.0
Embedded derivative of preferred interests and notes issued by CSF I and CSF II 8.3 16.7 8.3 16.6

Total 24.1 29.9 23.9 30.0


~~Note 11 —~~	~~Segment Reporting~~

The Company’s segment structure reflects NRG’s core areas of operation which are primarily the geographic regions of the Company’s wholesale power generation, thermal and chilled water business, and corporate activities. Within NRG’s wholesale power generation operations, there are distinct components with separate operating results and management structures for the following regions: Texas, Northeast, South Central, West and International.

Wholesale Power Generation
(In millions)
South

Three Months Ended September 30, 2008 Texas Northeast Central West International Thermal Corporate Elimination Total

Operating revenues $ 1,661 $ 677 $ 233 $ 40 $ 41 $ 36 $ 3 $ (1 ) $ 2,690
Depreciation and amortization 108 26 16 2 — 3 1 — 156
Equity in earnings of unconsolidated affiliates 40 — — 1 17 — — — 58
Income/(loss) from continuing operations before income taxes 1,050 351 24 13 25 4 (152 ) (1 ) 1,314
Income from discontinued operations, net of income taxes — — — — — — — — —

Net income/(loss)
$ 594 $ 351 $ 24 $ 13 $ 19 $ 4 $ (220 ) $ (1 ) $ 784

Total assets
$ 12,102 $ 1,634 $ 942 $ 53 $ 1,002 $ 212 $ 19,006 $ (11,268 ) $ 23,683

Wholesale Power Generation
(In millions)
South

Three Months Ended September 30, 2007 Texas Northeast Central West International Thermal Corporate Elimination Total

Operating revenues $ 956 $ 502 $ 200 $ 33 $ 38 $ 36 $ 7 $ — $ 1,772
Depreciation and amortization 113 25 17 1 — 3 1 — 160
Equity in earnings of unconsolidated affiliates — — — 1 18 — — — 19
Income/(loss) from continuing operations before income taxes 275 171 18 13 25 4 (96 ) — 410
Income from discontinued operations, net of income taxes — — — — 3 — — — 3

Net income/(loss)
$ 161 $ 171 $ 17 $ 13 $ 54 $ 4 $ (152 ) $ — $ 268

Wholesale Power Generation
(In millions) South

Nine Months Ended September 30, 2008 Texas Northeast Central West International Thermal Corporate Elimination Total

Operating revenues $ 3,061 $ 1,302 $ 584 $ 127 $ 122 $ 114 $ 1 $ (3 ) $ 5,308
Depreciation and amortization 334 77 50 6 — 8 3 — 478
Equity in (losses)/earnings of unconsolidated affiliates (10 ) — — (2 ) 47 — — — 35
Income/(loss) from continuing operations before income taxes 1,131 365 57 38 72 11 (339 ) (11 ) 1,324
Income from discontinued operations, net of income taxes — — — — 172 — — — 172

Net income/(loss)
$ 644 $ 365 $ 57 $ 38 $ 229 $ 11 $ (368 ) $ (11 ) $ 965

Wholesale Power Generation
(In millions) South

Nine Months Ended September 30, 2007 Texas Northeast Central West International Thermal Corporate Elimination Total

Operating revenues $ 2,526 $ 1,239 $ 514 $ 90 $ 102 $ 122 $ 29 $ (15 ) $ 4,607
Depreciation and amortization 341 74 51 2 — 9 4 — 481
Equity in (losses)/earnings of unconsolidated affiliates — — — (2 ) 42 — — — 40
Income/(loss) from continuing operations before income taxes 624 319 24 26 60 32 (304 ) (12 ) 769
Income from discontinued operations, net of income taxes — — — — 13 — — — 13

Net income/(loss)
$ 355 $ 319 $ 23 $ 26 $ 88 $ 32 $ (349 ) $ (12 ) $ 482

The shares are expected to be returned upon the termination of the financing agreements. Until the shares are returned, the shares will be treated as outstanding for corporate law purposes, and accordingly, the holders of the borrowed shares will have all of the rights of a holder of the Company’s outstanding shares, including the right to vote the shares on all matters submitted to a vote of the Company’s stockholders. However, because the CS affiliates must return all borrowed shares (or identical shares), the borrowed shares are not considered outstanding for the purpose of computing and reporting the Company’s basic or diluted earnings per share.


~~Note 12 —~~	~~Income Taxes~~

Income tax expense from continuing operations for the three months and nine months ended September 30, 2008 was $530 million and $531 million, respectively, compared to $145 million and $300 million for the three and nine months ended September 30, 2007, respectively. The income tax expense for the three months and nine months ended September 30, 2008 included domestic tax expense of $523 million and $515 million, respectively, and foreign tax expense of $7 million and $16 million, respectively. The income tax expense for the three and nine months ended September 30, 2007 included domestic tax expense of $171 million and $314 million, respectively, and a foreign tax benefit of $26 million and $14 million, respectively.

~~A reconciliation of the US statutory rate to NRG’s effective tax rate from continuing operations is as follows:~~

(In millions except percentages)

Nine Months Ended September 30, 2008 2007

Income from continuing operations before income taxes $ 1,324 $ 769

Tax at 35% 463 269
State taxes 62 37
Valuation allowance (1 ) 1
Foreign operations (10 ) (5 )
Foreign dividend 5 21
Non-deductible interest 24 7
Change in German tax rate — (30 )
Section 199 Manufacturing Deduction (17 ) (3 )
Other permanent differences including subpart F income 5 3

Income tax expense $ 531 $ 300

Effective income tax rate 40.1 % 39.0 %

The effective income tax rate for the nine months ended September 30, 2008 and 2007 differs from the US statutory rate of 35% due to a taxable dividend from foreign operations and non-deductible interest, offset by earnings in foreign jurisdictions that are taxed at rates lower than the US statutory rate.

~~Tax Payable~~Adoption of FSP APB 14-1
~~As of September 30, 2008, NRG recorded a current tax payable of $191 million for domestic federal and state taxes.~~
~~Deferred tax assets and valuation allowance~~
~~Net deferred tax balance~~— As of September 30, 2008, NRG recorded a net deferred tax liability of $560 million. However, due to an assessment of positive and negative evidence, including projected capital gains and available tax planning strategies, NRG believes that it is more likely than not that a benefit will not be realized on $539 million of tax assets, thus a valuation allowance has remained, resulting in a net deferred tax liability of $1,099 million.
~~NOL carryforwards~~ — As of September 30, 2008, the Company had cumulative foreign NOL carryforwards of $253 million, of which $54 million will expire starting in 2011 through 2017 and $199 million do not have an expiration date.
~~Uncertain tax benefits~~
NRG has identified certain unrecognized tax benefits whose after-tax value was $709 million, of which $36 million would impact the Company’s income tax expense. Of the $709 million in unrecognized tax benefits, $673 million relates to periods prior to the Company’s emergence from bankruptcy. In accordance with Statement of Position~~90-7,~~~~Financial Reporting by Entities in Reorganization under the Bankruptcy Code~~, and the application of fresh start accounting, recognition of previously unrecognized tax benefits existing pre-emergence would not impact the Company’s effective tax rate but would increase additional paid-in capital, or APIC. In accordance with SFAS 141R, any changes to our uncertain tax benefits occurring after January 1, 2009 will be credited to income tax expense rather than APIC.
As of September 30, 2008, NRG has recorded a $138 million non-current tax liability for unrecognized tax benefits, resulting from taxable earnings for the period, for which there are no NOLs available to offset for financial statement purposes. NRG accrued interest and penalties related to these unrecognized tax benefits of approximately $4 million as of September 30, 2008. The Company recognizes interest and penalties related to unrecognized tax benefits in income tax expense. For the nine months ended September 30, 2008, the Company incurred an immaterial amount of interest and penalties related to its unrecognized tax benefits.
~~Tax jurisdictions~~ — NRG is subject to examination by taxing authorities for income tax returns filed in the US federal jurisdiction and various state and foreign jurisdictions including major operations located in Germany and Australia. The Company is no longer subject to US federal income tax examinations for years prior to 2002. With few exceptions, state and local income tax examinations are no longer open for years before 2003. The Company’s significant foreign operations are also no longer subject to examination by local jurisdictions for years prior to 2000.
The Company has been contacted for examination by the Internal Revenue Service for years 2004 through 2006. The audit commenced during the third quarter 2008 and is expected to continue for approximately 18 to 24 months.

24
~~Note 13 —~~ ~~Benefit Plans and Other Postretirement Benefits~~
~~NRG Defined Benefit Plans~~
NRG sponsors and operates three defined benefit pension and other postretirement plans. The NRG Plan for Bargained Employees and the NRG Plan for Non-Bargained Employees are maintained solely for eligible legacy NRG participants. A third plan, the Texas Genco Retirement Plan, is maintained for participation solely by eligible Texas-based employees. The total amount of employer contributions paid for the nine months ended September 30, 2008 was $57 million. NRG expects to make $7 million in further contributions for the remainder of 2008.
~~The net periodic pension cost related to all of the Company’s defined benefit pension plans includes the following components:~~

Defined Benefit Pension Plans
Three Months Ended September 30, Nine Months Ended September 30,

(In millions) 2008 2007 2008 2007

Service cost benefits earned $   4 $   3 $   11 $   11
Interest cost on benefit obligation 4 4 13 13
Net gain — — (1 ) —
Expected return on plan assets (4 ) (3 ) (11 ) (9 )

Net periodic benefit cost $ 4 $ 4 $ 12 $ 15

~~The net periodic cost related to all of the Company’s other postretirement benefits plans include the following components:~~

Other Postretirement Benefits Plans
Three Months Ended September 30, Nine Months Ended September 30,

(In millions) 2008 2007 2008 2007

Service cost benefits earned $      1 $      1 $      2 $      2
Interest cost on benefit obligation 1 2 4 4

Net periodic benefit cost $ 2 $ 3 $ 6 $ 6

~~STP Defined Benefit Plans~~
NRG has a 44% undivided ownership interest in South Texas Project, or STP. South Texas Project Nuclear Operating Company, or STPNOC, which operates and maintains STP, provides its employees a defined benefit pension plan as well as postretirement health and welfare benefits. Although NRG does not sponsor the STP plan, it reimburses STPNOC for 44% of the contributions made towards its retirement plan obligations. The total amount of employer contributions reimbursed to STPNOC for the nine months ended September 30, 2008 was $4 million. The Company recognized net periodic costs related to its 44% interest in STP defined benefits plans of $2 million and $1 million for the three months ended September 30, 2008 and 2007, respectively. The Company recognized net periodic costs related to its 44% interest in STP defined benefits plan of $6 million and $5 million for the nine months ended September 30, 2008 and 2007, respectively.

25
~~Note 14 —~~ ~~Commitments and Contingencies~~
~~Commitments~~
~~Fuel Commitments~~
NRG enters into long-term contractual arrangements to procure fuel and transportation services for the Company’s generation assets. NRG entered into additional coal purchase agreements during the nine months ended September 30, 2008 with total commitments of approximately $465 million, spanning from 2008 through 2011. In addition, NRG’s natural gas purchase commitments have decreased by approximately $264 million during the nine months ended September 30, 2008 as the 2008 monthly commitments were settled.
~~First and Second Lien Structure~~
NRG has granted first and second liens to certain counterparties on substantially all of the Company’s assets in the United States in order to secure primarily long-term obligations under power and gas sale agreements and related contracts. NRG uses the first or second lien structure to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or MWh equivalents. To the extent that the underlying hedge positions for a counterparty are in-the-money to NRG, the counterparty would have no claim under the lien program. The lien program is limited by volumes hedged, not by the value of underlying out-of-the money positions. The first lien program does not require us to post collateral above any threshold amount of exposure. Within the first and second lien structure, the Company can hedge up to 80% of its baseload capacity and 10% of its non-baseload assets with these counterparties for the first rolling 60 months with such permitted hedging volumes declining thereafter. Net exposure to a counterparty on all trades must be positively correlated to the price of the relevant commodity for the first lien to be available to that counterparty. The first and second lien structure is not subject to unwind or termination upon a ratings downgrade of a counterparty.
~~As part of the amendments to NRG’s Senior Credit Facility entered into on June 8, 2007, the Company obtained the ability to move its second lien counterparty exposure to the first lien on a~~~~pari passu~~~~basis with the Company’s existing first lien lenders. In exchange for moving to a~~~~pari passu~~ ~~basis with the Company’s first lien lenders, the counterparties relinquished letters of credit issued by NRG which they held as a part of their collateral package.~~
The Company’s lien counterparties may have a claim on our assets to the extent their net positions are out-of-the-money. As of September 30, 2008 and October 23, 2008, the first lien exposure of net out-of-the-money positions to counterparties on hedges was $405 million and $185 million, respectively. As of September 30, 2008 and October 23, 2008, the second lien net out-of-the-money positions to counterparties on hedges were approximately $16 million and $2 million, respectively.
~~RepoweringNRG~~
~~NRG has made non-refundable payments relating to~~~~Repowering~~NRG projects totaling approximately $148 million primarily towards the procurement of wind turbines. The Company believes that these payments are necessary for the timely and successful execution of these projects. The payments are in support of expected deliveries of wind turbines and other equipment totaling approximately $248 million through 2009. In addition, as discussed ~~further~~ in Note 1,Basis of Presentation, the Company adopted FSP APB 14-1 on January 1, 2009. The following table summarizes certain information related to the CSF Debt in accordance with FSP APB 14-1:

March 31, December 31,
2009 2008

Equity Component

Additional Paid-in Capital $ 14 $ 14

Liability Component

Principal amount $ 333 $ 333
Unamortized discount (6 ) (8 )

Net carrying amount
$ 327 $ 325

     The unamortized discount will be amortized through the maturity of the CSF Debt. The CSF I debt has a maturity date of June 2010 and the CSF II debt has a maturity date October 2009. Interest expense for the CSF Debt, including the debt discount amortization for the three months ended March 31, 2009 and 2008 was $9 million and $10 million, respectively. The effective interest rate as of March 31, 2009 was 11.4% for the CSF I debt and 12.0% for the CSF II debt.
Subsequent events
Dunkirk Power LLC Tax-Exempt Bonds— On April 15, 2009, NRG ~~expects to contribute approximately $87~~executed a $59 million tax-exempt bond financing through its wholly owned subsidiary, Dunkirk Power LLC. The bonds were issued by the County of Chautauqua Industrial Development Agency and will be applied towards construction of emission control equipment on the Dunkirk Generating Station in ~~equity to Sherbino in 2008~~Dunkirk, NY. The bonds initially bear weekly interest based on the Securities Industry and ~~has posted~~Financial Markets Association, or SIFMA, rate, have a maturity date of April 1, 2042, and are enhanced by a letter of credit ~~in that amount. To date,~~under the Company’s Revolving Credit Facility covering amounts drawn on the facility. The initial proceeds were $31 million with the remaining balance being released over time as construction costs are paid.
GenConn Energy LLC related financings— On April 27, 2009, a wholly owned subsidiary of NRG ~~has made capital contributions to Sherbino~~closed on an equity bridge loan facility, or EBL, in the amount of ~~$17 million. Also, NRG’s~~$121.5 million from a syndicate of banks. The purpose of the EBL is to fund the Company’s proportionate share of ~~cash security posted~~the project construction costs required to ~~The Connecticut Light and Power Company by~~be contributed into GenConn Energy LLC, or GenConn, a ~~50/50 joint venture vehicle~~50% equity method investment of ~~NRG and~~the Company. The ~~United Illuminating Company,~~EBL, which is fully collateralized with a letter of credit issued under the Company’s Synthetic Letter of Credit Facility, will bear interest at a rate of LIBOR plus 2% on drawn amounts. The EBL will mature on the earlier of the commercial operations date of the Middletown project or July 26, 2011. The EBL also features a mandatory prepayment of the portion of the loan utilized for the Devon project (approximately $56 million) becoming due on the earlier of Devon’s commercial operations date or January 27, 2011. The initial proceeds of the EBL were $61 million and the remaining amounts will be drawn as necessary to fund construction costs.
     At the same time, GenConn secured financing from the same syndicate of banks for 50% of its project construction costs through a 7-year term loan facility, as well as a 5 year revolving working capital loan and letter of credit facility, collectively the GenConn Facility. The aggregate credit amount secured under the GenConn Facility, which is non-recourse to NRG, was $291 million, including $48 million for the revolving facility. No amounts were immediately drawn under the GenConn Facility.
22
Note 8 — Changes in Capital Structure
     The following table reflects the changes in NRG’s common stock issued and outstanding during the three months ended March 31, 2009:

Authorized Issued Treasury Outstanding

Balance as of December 31, 2008
500,000,000 263,599,200 (29,242,483 ) 234,356,717
Shares issued from LTIP — 199,135 — 199,135
Shares issued under NRG Employee Stock Purchase Plan, or ESPP — — 41,706 41,706
Shares borrowed by affiliates of CS — — 12,000,000 12,000,000
4.00% Preferred Stock conversion — 10,500 — 10,500
5.75% Preferred Stock conversion — 18,601,201 — 18,601,201

Balance as of March 31, 2009
500,000,000 282,410,036 (17,200,777 ) 265,209,259

Employee Stock Purchase Plan
     As of March 31, 2009, there remained 458,294 shares of treasury stock reserved for issuance under the ESPP.
5.75% Preferred Stock
     Certain holders of the Company’s 5.75% convertible perpetual preferred stock, or 5.75% Preferred Stock, elected to convert their preferred shares into NRG common shares prior to the mandatory conversion date of March 16, 2009 at ~~Devon Station~~the minimum conversion rate of 8.2712. As of March 16, 2009, each remaining outstanding share of the 5.75% Preferred Stock automatically converted into shares of common stock at a rate of 10.2564, based upon the applicable market value of NRG’s common stock. These conversions resulted in a decrease in preferred stock of $447 million, and a corresponding increase in Additional Paid-in Capital. The following table summarizes the conversion of the 5.75% Preferred Stock into NRG Common Stock:

Preferred Stock Conversion Rate Common Stock
Shares (per share) Shares

Balance as of December 31, 2008
1,841,680 —
Preferred shares converted by the holders prior to March 16, 2009 144,975 8.2712 1,199,116
Preferred shares automatically converted as of March 16, 2009 1,696,705 10.2564 17,402,085

Balance at March 31, 2009
— 18,601,201

4% Preferred Stock
     As of March 31, 2009, 210 shares of the 4% Preferred Stock were converted into 10,500 shares of common stock in 2009.
23
Note 9 — Equity Compensation
Non-Qualified Stock Options, or NQSO’s
     The following table summarizes the Company’s NQSO activity as of March 31, 2009, and changes during the three months then ended:

Weighted Aggregate Intrinsic
Average Value
Shares Exercise Price (In millions)

Outstanding as of December 31, 2008
4,008,188 $   25.84
Granted 1,195,600 23.64
Forfeited (8,967 ) 29.77

Outstanding at March 31, 2009
5,194,821 25.33 $   7
Exercisable at March 31, 2009
2,801,309 $   21.56 7

     The weighted average grant date fair value of NQSO’s granted for the three months ended March 31, 2009, was $8.55.
Restricted Stock Units, or RSU’s
     The following table summarizes the Company’s non-vested RSU awards as of March 31, 2009 and changes during the three months then ended:

Weighted Average
Grant-Date
Units Fair Value Per Unit

Non-vested as of December 31, 2008
1,061,996 $   32.97
Granted 147,000 23.64
Vested (288,578 ) 23.73
Forfeited (10,720 ) 39.55

Non-vested as of March 31, 2009
909,698 $   34.32

Performance Units, or PU’s
     The following table summarizes the Company’s non-vested PU awards as of March 31, 2009 and changes during the three months then ended:

Weighted Average
Grant- Date
Units Fair Value Per Unit

Non-vested as of December 31, 2008
659,564 $   22.81
Granted 285,200 22.73
Forfeited (216,064 ) 18.72

Non-vested as of March 31, 2009
728,700 $   24.16

     In the first quarter 2009, there were no performance unit payouts in accordance with the provisions.
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Note 10 — Earnings Per Share
     Basic earnings per share attributable to NRG common stockholders is ~~approximately $9 million.~~computed by dividing net income attributable to NRG adjusted for accumulated preferred stock dividends by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the year are weighted for the portion of the year that they were outstanding. The 12,000,000 shares outstanding under the Share Lending Agreements with CS affiliates are not treated as outstanding for earnings per share purposes because the CS affiliates must return all borrowed shares (or identical shares) upon termination of the Agreements. See Note 7 –Long-Term Debt,for more information on the Share Lending Agreements. Diluted earnings per share attributable to NRG common stockholders is computed in a manner consistent with that of basic earnings per share while giving effect to all potentially dilutive common shares that were outstanding during the period.
     The reconciliation of basic earnings per common share to diluted earnings per share attributable to NRG is as follows:

Three months ended March 31,
(In millions, except per share data) 2009 2008

Basic earnings per share attributable to NRG common stockholders

Numerator:

Income from continuing operations, net of income taxes $   198 $   45
Dividends for preferred shares (14 ) (14 )

Net income available to common stockholders from continuing operations 184 31
Income from discontinued operations, net of income taxes — 4
Net income attributable to NRG Energy, Inc. available to common stockholders $   184 $   35

Denominator:

Weighted average number of common shares outstanding 237.1 236.3
Basic earnings per share:

Income from continuing operations $   0.78 $   0.13
Income from discontinued operations, net of income taxes — 0.02

Net income attributable to NRG Energy, Inc. $   0.78 $   0.15

Diluted earnings per share attributable to NRG common stockholders

Numerator:

Net income available to common stockholders from continuing operations $   184 $   31
Add preferred stock dividends for dilutive preferred stock 10 —

Adjusted income from continuing operations 194 31
Income from discontinued operations, net of income taxes — 4

Net income attributable to NRG Energy, Inc. available to common stockholders $   194 $   35

Denominator:

Weighted average number of common shares outstanding 237.1 236.3
Incremental shares attributable to the issuance of equity compensation (treasury stock method) 1.0 3.7
Incremental shares attributable to embedded derivatives of certain financial instruments (if-converted method) — 5.3
Incremental shares attributable to assumed conversion features of outstanding preferred stock (if-converted method) 37.3 —

Total dilutive shares 275.4 245.3
Diluted earnings per share:

Income from continuing operations $   0.70 $   0.12
Income from discontinued operations, net of income taxes — 0.02

Net income attributable to NRG Energy, Inc. $   0.70 $   0.14

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     Effects on Earnings per Share
     The following table summarizes NRG’s outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company’s diluted earnings per share:

Three months ended March 31,
(In millions of shares) 2009 2008

Equity compensation (NQSO’s and PU’s) 5.4 1.3
4.0% convertible preferred stock — 21.0
5.75% convertible preferred stock — 16.5
Embedded derivative of 3.625% redeemable perpetual preferred stock 16.0 12.2
Embedded derivative of CSF preferred interests and notes 7.6 16.8

Total 29.0 67.8

Note 11 — Segment Reporting
     NRG’s segment structure reflects the Company’s core areas of operation which are primarily the geographic regions of the Company’s wholesale power generation, thermal and chilled water business, and corporate activities. Within NRG’s wholesale power generation operations, there are distinct components with separate operating results and management structures for the following regions: Texas, Northeast, South Central, West, and International.

Wholesale Power Generation
(In millions) South
Three months ended March 31, 2009 Texas Northeast Central West International Thermal Corporate Elimination Total

Operating revenues $ 925 $ 464 $ 162 $ 28 $ 34 $ 42 $ 4 $ (1 ) $ 1,658
Depreciation and amortization 117 29 17 2 — 2 2 — 169
Equity in earnings of unconsolidated affiliates 4 — — 1 17 — — — 22
Income/(loss) from continuing operations before income taxes 378 211 1 (3 ) 14 4 (109 ) — 496

Net income attributable to
NRG Energy, Inc.
$ 217 $ 211 $ 1 $ (3 ) $ 12 $ 4 $ (244 ) $ — $ 198

Total assets
$ 13,298 $ 1,687 $ 929 $ 262 $ 952 $ 206 $ 19,966 $ (13,102 ) $ 24,198

Wholesale Power Generation
(In millions) South
Three months ended March 31, 2008 Texas Northeast Central West International Thermal Corporate Elimination Total

Operating revenues $ 649 $ 360 $ 179 $ 38 $ 38 $ 44 $ (5 ) $ (1 ) $ 1,302
Depreciation and amortization 113 26 17 1 — 3 1 — 161
Equity in (losses)/earnings of unconsolidated affiliates (18 ) — — (2 ) 16 — — — (4 )
Income/(loss) from continuing operations before income taxes 67 59 39 12 24 5 (107 ) — 99
Income from discontinued operations, net of income taxes — — — — 4 — — — 4

Net income attributable to NRG Energy, Inc.
$ 37 $ 59 $ 39 $ 12 $ 24 $ 5 $ (127 ) $ — $ 49

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Note 12 — Income Taxes
~~Contingencies~~Effective Tax Rate
     Income taxes included in continuing operations were as follows:

Three months ended March 31,
(In millions except otherwise noted) 2009 2008

Income tax expense $ 298 $ 54
Effective tax rate 60.0% 54.5%

     For the three months ended March 31, 2009 and 2008, NRG’s overall effective tax rate on continuing operations was different than the statutory rate of 35% primarily due to state income taxes and an increase in valuation allowance as a result of capital losses generated in the quarter for which there are no projected capital gains or available tax planning strategies. In addition, NRG’s overall effective tax rate on continuing operations for the three months ended March 31, 2008 was impacted by a taxable dividend from foreign operations.
Valuation Allowance
     As of March 31, 2009, the Company’s valuation allowance was increased by approximately $96 million primarily due to losses generated in the first quarter from derivative trading activity which require capital treatment for tax purposes. The Company reduced its foreign valuation allowance by approximately $1 million.
Uncertain tax benefits
     NRG has identified certain unrecognized tax benefits whose after-tax value is $556 million, which would impact the Company’s income tax expense.
     As of March 31, 2009, NRG has recorded a $272 million non-current tax liability for unrecognized tax benefits, resulting from taxable earnings for the period for which there are no NOLs available to offset for financial statement purposes. NRG has accrued interest related to these unrecognized tax benefits of approximately $4 million for the three months ended March 31, 2009, and has accrued approximately $12 million since adoption. The Company recognizes interest and penalties related to unrecognized tax benefits in income tax expense.
     NRG is subject to examination by taxing authorities for income tax returns filed in the US federal jurisdiction and various state and foreign jurisdictions including major operations located in Germany and Australia. The Company is no longer subject to US federal income tax examinations for years prior to 2002. With few exceptions, state and local income tax examinations are no longer open for years before 2002. The Company’s significant foreign operations are also no longer subject to examination by local jurisdictions for years prior to 2000. The Company continues to be under examination by the Internal Revenue Service.
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Note 13 — Benefit Plans and Other Postretirement Benefits
NRG Defined Benefit Plans
     NRG sponsors and operates three defined benefit pension and other postretirement plans. The NRG Plan for Bargained Employees and the NRG Plan for Non-Bargained Employees are maintained solely for eligible legacy NRG participants. A third plan, the Texas Genco Retirement Plan, is maintained for participation solely by eligible Texas-based employees. The total amount of employer contributions paid for the three months ended March 31, 2009 was $6 million. NRG expects to make $24 million in further contributions for the remainder of 2009. The total 2009 planned contribution of $30 million was a decrease of $30 million from the expected contributions as disclosed in Note 12 —Benefit Plans and Other Postretirement Benefits, in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008. This decrease in the 2009 expected contributions is due to the adoption by the Company in March 2009 of the new funding method options now available. The new methods were made allowable under new IRS guidance on the application of recent Congressional legislation on funding requirements.
     The net periodic pension cost related to all of the Company’s defined benefit pension plans include the following components:

Defined Benefit Pension
(In millions) Plans
Three months ended March 31, 2009 2008

Service cost benefits earned $ 4 $ 4
Interest cost on benefit obligation 5 5
Expected return on plan assets (4 ) (4 )

Net periodic benefit cost $ 5 $ 5

     The net periodic cost related to all of the Company’s other post retirement benefits plans include the following components:

Other Postretirement
(In millions) Benefits Plans
Three months ended March 31, 2009 2008

Service cost benefits earned $ 1 $ 1
Interest cost on benefit obligation 2 1

Net periodic benefit cost $ 3 $ 2

STP Defined Benefit Plans
     NRG has a 44% undivided ownership interest in South Texas Project, or STP. South Texas Project Nuclear Operating Company, or STPNOC, which operates and maintains STP, provides its employees a defined benefit pension plan as well as postretirement health and welfare benefits. Although NRG does not sponsor the STP plan, it reimburses STPNOC for 44% of the contributions made towards its retirement plan obligations. There were no employer contributions reimbursed to STPNOC for the three months ended March 31, 2009. The Company recognized net periodic costs related to its 44% interest in STP defined benefits plans of $3 million and $2 million for the three months ended March 31, 2009 and 2008, respectively.
Note 14 — Commitments and Contingencies
Commitments
Fuel Commitments
     NRG enters into long-term contractual arrangements to procure fuel and transportation services for the Company’s generation assets. NRG’s total net coal commitments, which span from 2009 through 2012, decreased by approximately $120 million during the three months ended March 31, 2009 as the 2009 monthly commitments were settled. In addition, NRG’s natural gas purchase commitments decreased by approximately $124 million during the three months ended March 31, 2009, as the 2009 monthly commitments were settled and average natural gas prices decreased.
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First and Second Lien Structure
     NRG has granted first and second liens to certain counterparties on substantially all of the Company’s assets to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or MWh equivalents. The Company’s lien counterparties may have a claim on NRG’s assets to the extent market prices exceed the hedged price. As of March 31, 2009, and April 23, 2009, there was no exposure to out-of-the-money positions to counterparties on hedges under either the first or second liens.
RepoweringNRG Initiatives
     NRG has capitalized $32 million through March 31, 2009, for the repowering of its El Segundo generating facility in California. As a result of permitting delays related to on-going Natural Resource Defense Counsel claims, the El Segundo project will not reach its original completion date of June 1, 2011. The Company is contemplating certain PPA modifications including the commercial operations date.
Contingencies
Set forth below is a description of the Company’s material legal proceedings. The Company believes that it has valid defenses to these legal proceedings and intends to defend them vigorously. Pursuant to the requirements of SFAS No. 5,Accounting for Contingencies,, or SFAS 5, and related guidance, NRG records reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. In addition, legal costs are expensed as incurred. Management has assessed each of the following matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, the Company is unable to predict the outcome of these legal proceedings or reasonably estimate the scope or amount of any associated costs and potential liabilities. As additional information becomes available, management adjusts its assessment and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of the Company’s liabilities and contingencies could ~~be at amounts that are different~~vary from its currently recorded reserves and ~~that~~ such ~~difference~~differences could be material.

In addition to the legal proceedings noted below, NRG and its subsidiaries are party to other litigation or legal proceedings arising in the ordinary course of business. In management’s opinion, the disposition of these ordinary course matters will not materially adversely affect NRG’s consolidated financial position, results of operations, or cash flows.
Exelon Related Litigation
Delaware Chancery Court
     On November 11, 2008, Exelon and its wholly-owned subsidiary Exelon Xchange filed a complaint against NRG and NRG’s Board of Directors. The complaint alleges, among other things, that NRG’s Board of Directors failed to give due consideration and to take appropriate action in response to the acquisition proposal announced by Exelon on October 19, 2008, in which Exelon offered to acquire all of the outstanding shares of NRG common stock at an exchange ratio of 0.485 Exelon shares for each NRG common share. On November 14, 2008, NRG and NRG’s Board of Directors filed a motion to dismiss Exelon’s complaint on the grounds that it failed to state a claim upon which relief can be granted. On March 16, 2009, prior to responding to the motion to dismiss, Exelon and Exelon Xchange filed an amended complaint. The amended complaint seeks, among other things, declaratory and injunctive relief: (1) declaring that NRG and its Board of Directors breached its fiduciary duties by summarily rejecting the October 19, 2008 Exelon offer, by resorting to defensive measures to interfere with Exelon’s tender offer, and by making false and misleading statements to NRG stockholders; (2) compelling NRG and its Board of Directors to approve the Exelon tender offer by waiving the application of Section 203 of the Delaware General Corporation Law; (3) compelling NRG and its Board of Directors from taking any actions with respect to regulatory authorities that would thwart or interfere with the Exelon tender offer; and (4) compelling NRG and its Board of Directors to correct any false and misleading statements to NRG stockholders and to disclose all material facts necessary for NRG stockholders to make informed decisions regarding the October 19, 2008 Exelon offer. On April 17, 2009, NRG and NRG’s Board of Directors filed a partial motion to dismiss the amended complaint asserting that many of the claims are subject to the business judgment rule, are premature, and should be dismissed for failure to state a claim upon which relief can be granted. A schedule for briefing the motion will be agreed by the parties or set by the court.
29
     On December 11, 2008, the Louisiana Sheriffs’ Pension & Relief Fund and City of St. Claire Shores Police & Fire Retirement System, on behalf of themselves and all others similarly situated, served a previously filed complaint on NRG and its Board of Directors alleging substantially similar allegations as the Exelon complaint. On December 23, 2008, NRG and NRG’s Board of Directors filed a motion to dismiss the complaint on the grounds that it failed to state a claim upon which relief can be granted. On March 16, 2009, prior to responding to the motion to dismiss, these plaintiffs filed an amended complaint against only NRG’s Board of Directors. The amended complaint seeks, among other things, declaratory and injunctive relief: (1) declaring that it is a proper class action; (2) declaring that the NRG Board of Directors breached its fiduciary duties by summarily rejecting the October 19, 2008, Exelon offer and by resorting to defensive measures designed to prevent any potential acquirer from entering into a value-maximizing transaction with NRG; (3) compelling NRG’s Board of Directors to engage in a dialogue with Exelon to more fully understand the October 19, 2008, offer and to determine the potential for any improvement thereon; (4) enjoining NRG from proceeding with the acquisition of Reliant Energy’s retail business; (5) enjoining the NRG’s Board of Directors from taking any actions designed to block a transaction with Exelon; and (6) awarding plaintiffs their costs and fees. On April 17, 2009, the NRG Board of Directors filed a motion to dismiss the amended complaint asserting that it fails to state a claim upon which relief can be granted. A schedule for briefing the motion will be agreed by the parties or set by the court.
     On April 3, 2009, the Louisiana Sheriffs’ Pension & Relief Fund and City of St. Claire Shores Police & Fire Retirement System filed (1) a motion for injunctive relief to rescind the appointment of Pastor Kirbyjon H. Caldwell to NRG’s Board of Directors and to prevent the NRG Board from taking any action that would impede the vote for directors at the next annual meeting of NRG stockholders; and (2) a motion to expedite the injunction proceeding. The NRG Board of Directors filed its opposition to the motions on April 8, 2009, a telephonic hearing was held on April 9, 2009, and on April 14, 2009, the court denied both motions.
Mercer County, New Jersey Superior Court
     On January 6, 2009, three lawsuits previously filed against NRG and NRG’s Board of Directors on behalf of individual shareholders and all others similarly situated were consolidated into one case in the Law Division of the Superior Court of Mercer County, New Jersey. On January 21, 2009, the plaintiffs filed an Amended Consolidated Complaint in which they allege a single count of breach of fiduciary duty against NRG’s Board of Directors and seek injunctive relief: (1) declaring that the action is a class action and certifying plaintiffs as class plaintiffs and counsel as class counsel; (2) declaring that defendants breached their fiduciary duties by summarily rejecting the Exelon offer; (3) ordering defendants to negotiate with respect to the Exelon offer or with respect to another transaction to maximize shareholder value; (4) ordering defendants to exempt Exelon’s offer from Section 203 of the Delaware General Corporations Law; (5) awarding compensatory damages including interest; (6) awarding plaintiffs costs and fees; and (7) granting other relief the Court deems proper. On February 20, 2009, NRG’s Board of Directors filed a motion to dismiss the amended consolidated complaint for failure to state a claim or, in the alternative, to stay the action in favor of the Delaware Chancery Court proceedings. On March 19, 2009, the plaintiffs filed their response and on April 6, 2009, NRG’s Board of Directors filed its reply. On April 17, 2009, oral argument was held on the NRG Board of Director’s motion to dismiss. Additional oral argument will be scheduled by the court.
California Department of Water Resources

On December 19, 2006, the US Court of Appeals for the Ninth Circuit reversed the Federal Energy Regulatory Commission’s, or FERC’s, prior determinations regarding the enforceability of certain wholesale powerThis matter concerns, among other contracts and ~~remanded the case to FERC for further proceedings consistent with the decision. One of these contracts was the wholesale power contract between~~other defendants, the California Department of Water Resources, or CDWR, and its wholesale power contract with subsidiaries of WCP (Generation) Holdings, Inc., or WCP. ~~This~~The case originated with a February 2002 complaint filed ~~at FERC~~ by the State of California alleging that many parties, including WCP subsidiaries, overcharged the ~~State.~~State of California. For WCP, the alleged overcharges totaled approximately $940 million for 2001 and 2002. The complaint demanded that the Federal Energy Regulatory Commission, or FERC, abrogate the CDWR contract and sought refunds associated with revenues collected under the contract. In 2003, the FERC rejected this complaint, denied rehearing, and the case was appealed to the US Court of Appeals for the Ninth Circuit where oral argument was held on December 8, 2004. On December 19, 2006, the ~~Court~~Ninth Circuit decided that in the FERC’s review of the contracts at issue, the FERC could not rely on the ~~Mobil-Sierra~~ Mobile-Sierrastandard presumption of just and reasonable rates, where such contracts were not reviewed by the FERC with full knowledge of the then existing market conditions. ~~On May 3, 2007,~~ WCP and ~~the other defendants filed separate petitions for certiorari seeking~~others sought review by the US Supreme Court. OnWCP’s appeal was not selected, but instead held by the Supreme Court. In the appeal that was selected by the Supreme Court, on June 26, 2008, the Supreme Court ~~issued its decision. The Court held~~ruled: (1) that the~~Mobil-Sierra~~Mobile-Sierrapublic interest standard of review applied to contracts made under a seller’s market-based rate authority; (2) that the public interest “bar” required to set aside a contract remains a very high one to overcome; and (3) that the~~Mobil-Sierra~~Mobile-Sierrapresumption of contract reasonableness applies when a contract is formed during a period of market dysfunction unless (a) such market conditions were caused by the illegal actions of one of the parties or (b) the contract negotiations were tainted by fraud or duress. ~~The~~In this related case, the US Supreme Court affirmed the Ninth Circuit’s decision agreeing that the case should be remanded to FERC to clarify FERC’s 2003 reasoning regarding its rejection of the original complaint relating to the financial burdens under the contracts at issue and to alleged market manipulation at the time these contracts were formed. ~~Although WCP’s petition for review was not heard by~~As a result, the US Supreme Court then reversed and remanded the ~~Supreme Court’s decision with respect~~WCP CDWR case to the ~~Morgan Stanley petition applies equally to WCP.~~
Ninth Circuit for treatment consistent with its June 26, 2008 decision in the related case. On October 20, 2008, the Ninth Circuit ~~ordered~~asked the
30
parties in the remanded CDWR case, including ~~FERC, to submit short briefs on~~WCP and the ~~question of~~FERC, whether that Court should answer a question ~~that~~ the US Supreme Court did not address in its June 26, 2008, ~~decision. That question is~~decision; whether the~~Mobil-Sierra~~Mobile-Sierradoctrine applies to a third-party that was not a signatory to any of the wholesale power contracts, including the CDWR contract, at issue in that case. Without answering that reserved question, on December 4, 2008, the ~~case. WCP’s response is due November~~Ninth Circuit vacated its prior opinion and remanded the WCP CDWR case back to the FERC for proceedings consistent with the US Supreme Court’s June 26, 2008, decision. On December 15, 2008, WCP and the other seller-defendants filed with FERC a Motion for Order Governing Proceedings on Remand. On January 14, ~~2008.~~2009, the Public Utilities Commission of the State of California filed an Answer and Cross Motion for an Order Governing Procedures on Remand, and on January 28, 2009, WCP and the other seller-defendants filed their reply.

At this time, while NRG cannot predict with certainty whether WCP will be required to make refunds for rates collected under the CDWR contract or estimate the range of any such possible refunds, a reconsideration of the CDWR contract by the FERC with a resulting order mandating significant refunds could have a material adverse impact on NRG’s financial position, statement of operations, and statement of cash flows. As part of the 2006 acquisition of Dynegy’s 50% ownership interest in WCP, WCP and NRG assumed responsibility for any risk of loss arising from this case, unless any such loss was deemed to have resulted from certain acts of gross negligence or willful misconduct on the part of Dynegy, in which case any such loss would be shared equally between WCP and Dynegy.
     On April 27, 2009, the US Supreme Court grantedcertiorariin an unrelated proceeding involving theMobile-Sierradoctrine that may affect the standard of review applied to the CDWR contract on remand before the FERC. Specifically, on March 18, 2008, the U.S. Court of Appeals for the DC Circuit rejected the appeals filed by the Attorneys General of the State of Connecticut and Commonwealth of Massachusetts regarding the settlement that established the current New England capacity market. That settlement, filed with FERC on March 7, 2006, provides for interim capacity transition payments for all generators in New England for the period starting December 1, 2006 through May 31, 2010, and for the Forward Capacity Market thereafter. The Court of Appeals rejected all substantive challenges to the settlement, but sustained one procedural argument relating to the applicability of theMobile-Sierradoctrine to non-settling parties. After the Court of Appeals denied rehearingen banc, NRG sought certiorari before the US Supreme Court, which was granted on April 27, 2009.
Louisiana Generating, LLC
     On February 11, 2009, the US Department of Justice acting at the request of the US Environmental Protection Agency, or USEPA, commenced a lawsuit against Louisiana Generating, LLC in federal district court in the Middle District of Louisiana alleging violations of the Clean Air Act, or CAA, at the Big Cajun II power plant. This is the same matter for which Notices of Violation, or NOVs, were issued to Louisiana Generating, LLC on February 15, 2005, and on December 8, 2006. Specifically, it is alleged that in the late 1990’s, several years prior to NRG’s acquisition of the Big Cajun II power plant from the Cajun Electric bankruptcy and several years prior to the NRG bankruptcy, modifications were made to Big Cajun II Units 1 and 2 by the prior owners without appropriate or adequate permits and without installing and employing the best available control technology, or BACT, to control emissions of nitrogen oxides and/or sulfur dioxides. The relief sought in the complaint includes a request for an injunction to: (1) preclude the operation of Units 1 and 2 except in accordance with the CAA; (2) order the installation of BACT on Units 1 and 2 for each pollutant subject to regulation under the CAA; (3) obtain all necessary permits for Units 1 and 2; (4) order the surrender of emission allowances or credits; (5) conduct audits to determine if any additional modifications have been made which would require compliance with the CAA’s Prevention of Significant Deterioration program; (6) award to the Department of Justice its costs in prosecuting this litigation; and (7) assess civil penalties of up to $27,500 per day for each CAA violation found to have occurred between January 31, 1997, and March 15, 2004, up to $32,500 for each CAA violation found to have occurred between March 15, 2004, and January 12, 2009, and up to $37,500 for each CAA violation found to have occurred after January 12, 2009.
     On April 27, 2009, Louisiana Generating, LLC made several filings. First, it filed an objection in the Cajun Electric Cooperative Power, Inc.’s bankruptcy proceeding challenging the February 19, 2009, Motion for Final Decree, Discharge of the Trustee, and For Order Closing the Chapter 11 Case, to prevent the bankruptcy from closing. The objection was filed in the U.S. Bankruptcy Court for the Middle District of Louisiana. Second, it filed a complaint in the same bankruptcy proceeding in the same court seeking a judgment that: (i) it did not assume liability from Cajun Electric for any claims or other liabilities under environmental laws with respect to Big Cajun II that arose, or are based on activities that were undertaken, prior to the closing date of the acquisition; (ii) it is not otherwise the successor to Cajun Electric; and (iii) Cajun Electric and/or the Bankruptcy Trustee are exclusively liable for the violations alleged in the February 11, 2009, lawsuit to the extent that such claims are determined to have merit. Last, it filed in the federal district court for the Middle District of Louisiana a Motion for an Extension of Time to File Responsive Pleadings arguing that the court should extend the May 11, 2009, deadline to respond to the February 11, 2009, lawsuit until such time as directed by the court following resolution of Louisiana Generating, LLC’s Motion for Stay of Proceedings Pending Resolution of Certain Bankruptcy Actions filed concurrently with the Motion for an Extension of Time.

2731
~~Station Service Disputes~~Citizens for Clean Power

On ~~October~~November 6, 2008, Citizens for Clean Power, or CCP, filed a notice of its intent to file a lawsuit under the CAA against Indian River Power, LLC, or IRP, seeking to enforce opacity limitations applicable to units 1, 2, ~~2000, Niagara Mohawk Power Corporation,~~3, and 4. On January 5, 2009, the Delaware Department of Natural Resources and Environmental Control, or ~~NiMo, commenced an~~DNREC, filed a lawsuit relating to opacity issues against IRP in the Superior Court in Kent County, Delaware. On January 6, 2009, DNREC and IRP agreed to a consent order resolving the DNREC action ~~against NRG~~ in ~~New York state court seeking damages related to NRG’s alleged failure~~which IRP agreed to pay ~~retail tariff amounts for utility services at the Dunkirk plant between June 1999~~a $5,000 civil penalty and ~~September 2000. The parties~~ agreed to ~~consolidate this action~~purchase for DNREC’s use an Ultrafine Particle Monitor for approximately $60,000. The consent order was filed with ~~two other actions against~~ the ~~Huntley~~court on February 6, 2009, and ~~Oswego plants.~~entered by the court on February 13, 2009, thereby precluding CCP’s ability under the CAA to commence its noticed lawsuit. On ~~October 8, 2002, by stipulation and order, this action was stayed pending submission to FERC~~February 26, 2009, notwithstanding the entry of the disputes in the action. At FERC, NiMo asserted the same claims and legal theories, and on November 19, 2004, FERC denied NiMo’s petition and ruled that the NRG facilities could net their service obligations over each 30 calendar day period from the day NRG acquired the facilities. In addition, FERC ruled that neither NiMo nor the New York Public Service Commission could impose a retail delivery charge on the NRG facilities because they are interconnected to transmission and not to distribution. NiMo appealed to the US Court of Appeals for the D.C. Circuit which, on June 23, 2006, denied the appeal finding that New York Independent System Operator’s, or NYISO’s, station service program that permits generators to self supply their station power needs by netting consumption against production in a month is lawful. On April 30, 2007, the US Supreme Court denied NiMo’s request for review of the D.C. Circuit decision thus ending further avenues to appeal FERC’s ruling in this matter. NRG believes it is adequately reserved.
On December 14, 1999, NRG acquired certain generating facilities from CL&P. A dispute arose over station service power and delivery services provided to the facilities. On December 20, 2002, as a result of a petition filed at FERC by Northeast Utilities Services Company on behalf of itself and CL&P, FERC issued anconsent order, finding that, at times when NRG is not able to self-supply its station power needs, there is a sale of station power from a third-party and retail charges apply. In August 2003, the parties agreed to submit the dispute to binding arbitration. On September 11, 2007, the parties argued the dispute before a three judge arbitration panel. On February 19, 2008, the parties executed a settlement agreement ending the arbitration, and on April 30, 2008, that settlement agreement became effective thereby ending the case.
~~Native Village of Kivalina and City of Kivalina~~
Twenty-four electric generating companies and oil and gas companies were named as defendants in this complaint, in which damages of up to $400 million had been asserted. The complaint was filed on behalf of a small Alaskan town and sought damages associated with the need to relocate from the northern coast of Alaska purportedly because of the effects of global warming caused by the defendant’s CO₂ emissions. On June 11, 2008, NRG and the plaintiffs executed a Stipulation of Dismissal with Prejudice and on June 16, 2008, the US District Court for the Northern District of California dismissed NRG with prejudice thereby ending the case for NRG. The Company had argued to the plaintiffs that their allegations were blocked by NRG’s 2003 bankruptcy. NRG did not pay any money or exchange anything of value with the plaintiffs in exchange for its dismissal.
~~Spring Creek Coal Company~~
~~In August 2007, Spring Creek Coal Company~~CCP filed a complaint against ~~NRG Texas LP, NRG South Texas LP, NRG Texas Power LLC, NRG Texas LLC, and NRG Energy, Inc.~~IRP, in ~~the US District Court for the~~ federal district ~~of Wyoming.~~court in Delaware. The complaint ~~alleged multiple breaches~~seeks injunctive and declarative relief in ~~2007~~addition to civil penalties: (1) declaring that IRP violated the CAA through 6,304 opacity violations between 2004 and 2008; (2) seeking civil penalties of up to $32,500 for each such violation; (3) enjoining IRP from violating the CAA; (4) ordering IRP to assess and mitigate any environmental injuries caused by its emissions; and (5) awarding CCP its fees and costs. On March 25, 2009, IRP filed a ~~1978 coal supply agreement as amended by a later 1987 agreement, which plaintiff alleges is a “take or pay” contract. On~~motion to dismiss the complaint, on April ~~10, 2008, the parties reached a settlement in principal ending the litigation~~7, 2009, CCP filed its opposition, and on May 5, 2008, the parties executed a settlement agreement. On May 15, 2008, the case was dismissed with prejudice thereby ending the matter. While neither party admitted liability in the settlement, NRG paid Spring Creek approximately $18 million for the amount of coal it did not take in 2007 and NRG’s obligation to take coal under the coal supply agreement in the future was reduced by an identical amount. In addition, NRG is receiving a price reduction on all remaining tons under the coal supply agreement valued at approximately $3 million. NRG recorded expense of $15 million in connection with the settlement.April 20, 2009, IRP filed its reply.
Disputed Claims Reserve

As part of NRG’s plan of reorganization, NRG funded a disputed claims reserve for the satisfaction of certain general unsecured claims that were disputed claims as of the effective date of the plan. Under the terms of the plan, as such claims are resolved, the claimants are paid from the reserve on the same basis as if they had been paid out in the bankruptcy. To the extent the aggregate amount required to be paid on the disputed claims exceeds the amount remaining in the funded claims reserve, NRG will be obligated to provide additional cash and common stock to satisfy the claims. Any excess funds in the disputed claims reserve will be reallocated to the creditor pool for the pro rata benefit of all allowed claims. The contributed common stock and cash in the reserves is held by an escrow agent to complete the distribution and settlement process. Since NRG has surrendered control over the common stock and cash provided to the disputed claims reserve, NRG recognized the issuance of the common stock as of December 6, 2003 and removed the cash amounts from the balance sheet. Similarly, NRG removed the obligations relevant to the claims from the balance sheet when the common stock was issued and cash contributed.

28

On April 3, 2006, the Company made a supplemental distribution to creditors under the Company’s Chapter 11 bankruptcy plan, totaling $25 million in cash and 5,082,000 shares of common stock. As of October 23, 2008, the reserve held approximately $10 million in cash and approximately 1,319,142 shares of common stock. NRG believes the cash and stock together represent sufficient funds to satisfy all remaining disputed claims. During the fourth quarter ofOn December 18, 2008, NRG ~~expects to file~~filed with the US Bankruptcy Court for the Southern District of New York a Closing Report and an Application for Final Decree Closing the Chapter 11 Case for NRG Energy, Inc. et ~~al.~~al and on December 29, 2008, the court entered the Final Decree. As of December 21, 2008, the reserve held approximately $9.8 million in cash and 1,282,783 shares of common stock. On December 21, 2008, the Company issued an instruction letter to The Bank of New York Mellon to distribute all remaining cash and stock in the Disputed Claims Reserve to NRG’s creditors. On January 12, 2009, The Bank of New York Mellon commenced the distribution of all remaining cash and stock in the Disputed Claim Reserve to the Company’s creditors pursuant to NRG’s Chapter 11 bankruptcy plan.
Note 15 — Regulatory Matters

~~Note 15 —~~ ~~Regulatory Matters~~
NRG operates in a highly regulated industry and is subject to regulation by various federal and state agencies. As such, NRG is affected by regulatory developments at both the federal and state levels and in the regions in which NRG operates. In addition, NRG is subject to the market rules, procedures and protocols of the various ISO markets in which NRG participates. These wholesale power markets are subject to ongoing legislative and regulatory changes.

~~New England~~PJM — — On July 16, 2007, FERC conditionally accepted, subject to refund, the Reliability-Must-Run, or RMR, agreement filed on April 26, 2007 by Norwalk Power for its units 1 and 2, specifying a June 19, 2007 effective date. Norwalk’s RMR rate and its eligibility for the RMR agreement, which is based upon the facility’s projected market revenues and costs, are subject to further proceedings. Norwalk filed for the RMR agreement in response to FERC’s order eliminating the Peaking Unit Safe Harbor bidding mechanism which took effect on June 19, 2007. Settlement proceedings are still ongoing.
OnBy Order dated March ~~18, 2008,~~17, 2009, the US Court of Appeals for the ~~D.C.~~DC Circuit ~~rejected~~denied the ~~appeal filed by the Attorneys General~~remaining appeals of the ~~State~~FERC orders establishing the RPM capacity market. In February of ~~Connecticut and Commonwealth of Massachusetts regarding~~2009, the settlement of the New England capacity market design. The settlement, filed with FERC on March 7, 2006, by a broad group of New England market participants, provides for interim capacity transition payments for all generators in New England for the period starting December 1, 2006 through May 31, 2010, and a Forward Capacity Market, or FCM, for the period thereafter. All substantive challenges to the settlement, to the validity of the interim capacity transition payments, and to the market design were rejected by the D.C. Circuit, although one procedural argument relating to future challenges by non-settling parties was sustained. Several parties sought rehearing on this issue due to concerns regarding the sanctity of contracts. On October 6, 2008, the D.C. Circuit denied all requests for rehearing.
~~New York~~ — On March 7, 2008, FERC issued an order accepting the NYISO’s proposed market reforms to the in-city Installed Capacity, or ICAP, market, with only minor modifications. On October 4, 2007, the NYISO had filed its proposal for revising the ICAP market for the New York City zone. The proposal retains the existing ICAP market structure, but imposes additional market power mitigation on the current owners of Consolidated Edison’s divested generation units in New York City (which include NRG’s Arthur Kill and Astoria facilities), who are deemed to be pivotal suppliers. Specifically, the NYISO proposal imposes a new reference price on pivotal suppliers and requires bids to be submitted at or below the reference price. The new reference price is derived from the expected clearing price based upon the intersection of the supply curve and the ICAP Demand Curve if all suppliers bid as price-takers. The NYISO’s proposed reforms became effective March 27, 2008. Although FERC had established a refund effective date of May 12, 2007, its March 7 order determined that the NYISO’s proposal should be implemented only prospectively and that no refunds should be required. No party sought rehearing on the refund issue, thus resolving the contingency. On September 29, 2008, FERC issued its order on rehearing and the NYISO’s compliance filings that substantially reaffirmed the NYISO’s proposed market reforms.
On March 15, 2006, NRG received the results from NYISO Market Monitoring Unit’s review of NRG’S Astoria plant’s 2004 Generating Availability Data System, or GADS, reporting. On July 25, 2008, the NYISO determined that it would assess NRG a capacity deficiency charge relating to the Astoria plant as a result of a restatement of its GADS data for 2004. NRG agreed to and paid the NYISO’s assessment.
~~PJM~~ ~~— On August 23, 2007, several~~ entities representing load interests, including the New Jersey Board of Public Utilities, the District of Columbia Office of the People’s Counsel, and the Maryland Office of People’s Counsel, ~~filed~~agreed to withdraw their appeals regarding the establishment of the ~~FERC orders accepting the settlement of the locational capacity~~RPM market for PJM Interconnection, LLC. The settlement, filed at FERC on September 29, 2006, provides for a capacity market mechanism known as the Reliability Pricing Model, or RPM, which is designed to provide a long-term price signal through competitive forward auctions.design.
     On December 22, 2006, FERC issued an order accepting the settlement, which was reaffirmed on rehearing by order dated June 25, 2007. The RPM auctions have been conducted and capacity payments pursuant to the RPM mechanism have commenced. A successful appeal by the appellants could disturb the settlement and create a refund obligation of capacity payments.

29
~~On January 15,~~May 30, 2008, the Maryland Public Service Commission or MDPSC, filed at FERC a complaint against PJM claiming that PJM had failed to adequately mitigate certain generation resources, due to exemptions for resources used to relieve reactive limits on interfaces or that were constructed during certain periods after 1999. In addition to seeking an order eliminating the exemptions and a refund effective date as of the date of the complaint, the MDPSC sought an investigation of periods prior to the complaint that could have led to disgorgement by certain entities, and possibly a resettlement of the market. On May 16, 2008, FERC issued an order granting in part, and dismissing in part, the complaint and establishing a proceeding to examine the justness and reasonableness of PJM’s other market power mitigation mechanisms. FERC denied the request for retroactive relief and resettlement of the market.
~~On May 30, 2008, the MDPSC,~~ together with other load interests, filed atwith FERC a complaint against PJM challenging the results of the RPM transition Base Residual Auctions for installed capacity, held between April 2007 and January 2008. The complaint ~~seeks~~sought to replace the auction-determined results for installed capacity for the 2008/2009, 2009/2010, and 2010/2011 delivery years with administratively-determined prices. On September 19, 2008, FERC dismissed the complaint. The parties representing load interests have sought rehearing of the dismissal of the ~~complaint. In~~complaint, and a ~~related proceeding,~~reversal by FERC, ~~directed PJM to commence stakeholder processes towards addressing issues with RPM and required PJM to make~~could result in a ~~filing of proposed changes to RPM no later than December 15, 2008.~~refund obligation.
32
Note 16 — Environmental Matters

~~Note 16 —~~ ~~Environmental Matters~~
The construction and operation of power projects are subject to stringent environmental and safety protection and land use laws and regulation in the US. If such laws and regulations become more stringent, or new laws, interpretations or compliance policies apply and NRG’s facilities are not exempt from coverage, the Company could be required to make modifications to further reduce potential environmental impacts. New legislation and regulations to mitigate the effects of greenhouse ~~gas,~~gases, or ~~GHG,~~GHGs, including CO₂ from power plants, are under consideration at the federal and state levels. In general, the effect of such future laws or regulations is expected to require the addition of pollution control equipment or the imposition of restrictions or additional costs on the Company’s operations.

Environmental Capital Expenditures

Based on current rules, technology and plans, NRG has estimated that environmental capital expenditures to be incurred ~~from 2008~~during the remainder of 2009 through 2013 to meet NRG’s environmental commitments will be approximately ~~$1.3~~$1.1 billion. These capital expenditures, in general, are related to installation of particulate, SO₂, ~~NOx,~~NO_x, and mercury controls to comply with federal and state air quality rules and consent orders, as well as installation of “Best Technology Available” under the Phase II 316(b) ~~rule.~~Rule. NRG continues to explore cost effective alternatives that can achieve desired results. ~~While this~~This estimate reflects anticipated ~~changes in~~ schedules and controls related to ~~recent court rulings that vacate both~~ the Clean Air Interstate Rule, or CAIR, Maximum Achievable Control Technology, or MACT, for mercury, and the ~~Clear Air Mercury Rule, or CAMR,~~Phase II 316(b) rule which are under remand to the USEPA, and, as such, the full impact on the scope and timing of environmental retrofits from any new or revised~~and/or~~ ~~replacement~~ regulations cannot be determined at this time.

Northeast Region

~~On December 20, 2005, 10 northeastern states entered into a Memorandum of Understanding, or MOU, to create the Regional Greenhouse Gas Initiative, or RGGI, to establish acap-and-trade~~ ~~GHG program for~~NRG operates electric ~~generators. Electric~~ generating units located in ~~participating RGGI states will have~~Connecticut, Delaware, Maryland, Massachusetts and New York which are subject to ~~procure~~RGGI. These units must surrender one allowance for every US ton of CO₂ emitted with true up for2009-2011 occurring in 2012. ~~NRG units located~~Allowances are partially allocated only in ~~Connecticut, Delaware, Maryland, Massachusetts and New York~~the state of Delaware. In 2008, NRG emitted approximately 1312 million ~~US tons~~tonnes of CO₂ in ~~2007.~~RGGI states, although 2009 is tracking lower than 2008 year to date. NRG believes that to the extent ~~allowance costs~~ CO₂will not be fully reflected in wholesale electricity prices, the direct financial impact on the Company is likely to be negative as costs ~~are~~will be incurred ~~to secure~~in the course of securing the necessary RGGI allowances and offsets at auction and in the market.
     In January 2006, NRG’s Indian River Operations, Inc. received a letter of informal notification from the DNREC stating that the Company may be a potentially responsible party with respect to a historic captive landfill. On October 1, 2007, NRG signed an agreement with DNREC to investigate the site through the Voluntary Clean-up Program. On February 4, 2008, the DNREC issued findings that no further action is required in relation to surface water and that a previously planned shoreline stabilization project would adequately address shore line erosion. The landfill itself will require a further Remedial Investigation and Feasibility Study to determine the type and scope of any additional work required. Until the Remedial Investigation and Feasibility Study are completed, the Company is unable to predict the impact of any required remediation.
On May 29, 2008, the ~~Delaware Department of Natural Resources, or~~ DNREC issued an invitation to NRG’s Indian River Operations, Inc. to participate in the development and performance of a Natural Resource Damage Assessment, or NRDA, at the Burton Island Old Ash Landfill. NRG is currently working with the DNREC and other ~~Trustees~~trustees to close out the property.

30
~~South Central Region~~Note 17 — Guarantees

On January 27, 2004, NRG’s Louisiana Generating LLC and the Company’s Big Cajun II plant received a request under Section 114 of the Clean Air Act, or CAA, from USEPA seeking information primarily related to physical changes made at the Big Cajun II plant, and subsequently received a notice of violation, or NOV, on February 15, 2005, alleging that NRG’s predecessors had undertaken projects that triggered requirements under the Prevention of Significant Deterioration, or PSD, program, including the installation of emission controls. NRG submitted multiple responses commencing February 27, 2004 and ending on October 20, 2004. On May 9, 2006, these entities received from the Department of Justice, or DOJ, a notice of deficiency related to their responses, to which NRG responded on May 22, 2006. A document review was conducted at NRG’s Louisiana Generating LLC offices by the DOJ during the week of August 14, 2006. On December 8, 2006, the USEPA issued a supplemental NOV updating the original February 15, 2005 NOV. Discussions with the USEPA are ongoing and the Company cannot predict with certainty the outcome of this matter.
~~Note 17 —~~ ~~Guarantees~~
NRG and its subsidiaries enter into various contracts that include indemnification and guarantee provisions as a routine part of the Company’s business activities. Examples of these contracts include asset purchases and sale agreements, commodity sale and purchase agreements, joint venture agreements, EPC agreements, operation and maintenance agreements, service agreements, settlement agreements, and other types of contractual agreements with vendors and other third ~~parties.~~parties, as well as affiliates. These contracts generally indemnify the counterparty for tax, environmental liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. In some cases, NRG’s maximum potential liability cannot be estimated, since the underlying agreements contain no limits on potential liability.

This footnote should be read in conjunction with the complete description under Note 25,Guarantees, to the Company’s financial statements in its Annual Report onForm 10-K for the year ended December 31, ~~2007.~~2008.
33

~~For the nine months ended September 30, 2008, NRG had net increases to its guarantee obligations under other commercial arrangements of approximately $202 million.~~

31
     In connection with the agreement to sell its 50% ownership interest in Mibrag B.V., NRG signed an agreement guaranteeing the performance of its subsidiary Lambique Beheer under the purchase and sale agreement. The Company’s guarantee is limited to EUR 206 million, which represents the expected sales proceeds including expected interest through closing. In addition, the Company guaranteed the performance of NRGenerating International B.V. under a currency exchange agreement related to the proceeds of the sale of MIBRAG. The guarantee is limited to $35 million. NRG has no reason to believe that the Company currently has any material liability relating to such routine indemnification obligations.
~~Note 18 —~~ ~~Condensed Consolidating Financial Information~~
     NRG signed a guarantee agreement on behalf of its subsidiary NRG Retail, LLC guaranteeing the payment and performance of its obligations under the LLC Membership Interest Purchase Agreement and related agreements with Reliant Energy in connection with the purchase of its retail business, including the purchase price of $287.5 million and an additional $2.6 million for additional marketing services agreed upon as part of the transaction. NRG has no reason to believe that the Company currently has any material liability relating to such routine indemnification obligations.
Note 18 — Condensed Consolidating Financial Information
As of ~~September 30, 2008,~~March 31, 2009, the Company had $1.2 billion of 7.25% Senior Notes due 2014, $2.4 billion of 7.375% Senior Notes due 2016 and $1.1 billion ~~of 7.375%~~ Senior Notes due 2017 outstanding. These notes are guaranteed by certain of NRG’s current and future wholly-owned domestic subsidiaries, or guarantor subsidiaries.

Each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of ~~September 30, 2008:~~March 31, 2009:

Arthur Kill Power LLC NRG Construction LLC
Astoria Gas Turbine Power LLC NRG Devon Operations Inc.
Berrians I Gas Turbine Power LLC NRG Dunkirk Operations, Inc.
Big Cajun II Unit 4 LLC NRG El Segundo Operations Inc.
Cabrillo Power I LLC NRG Generation Holdings, Inc.
Cabrillo Power II LLC NRG Huntley Operations Inc.
Chickahominy River Energy Corp. NRG International LLC
Commonwealth Atlantic Power LLC NRG Kaufman LLC
Conemaugh Power LLC NRG Mesquite LLC
Connecticut Jet Power LLC NRG MidAtlantic Affiliate Services Inc.
Devon Power LLC NRG Middletown Operations Inc.
Dunkirk Power LLC NRG Montville Operations Inc.
Eastern Sierra Energy Company NRG New Jersey Energy Sales LLC
El Segundo Power, LLC NRG New Roads Holdings LLC
El Segundo Power II LLC NRG North Central Operations, Inc.
GCP Funding Company LLC NRG Northeast Affiliate Services Inc.
Hanover Energy Company NRG Norwalk Harbor Operations Inc.
Hoffman Summit Wind Project LLC NRG Operating Services Inc.
Huntley IGCC LLC NRG Oswego Harbor Power Operations Inc.
Huntley Power LLC NRG Power Marketing LLC
Indian River IGCC LLC NRG Rocky Road LLC
Indian River Operations Inc. NRG Saguaro Operations Inc.
Indian River Power LLC NRG South Central Affiliate Services Inc.
James River Power LLC NRG South Central Generating LLC
Kaufman Cogen LP NRG South Central Operations Inc.
Keystone Power LLC NRG South Texas LP
Lake Erie Properties Inc. NRG Texas LLC
Louisiana Generating LLC NRG Texas Power LLC
Middletown Power LLC NRG West Coast LLC
Montville IGCC LLC NRG Western Affiliate Services Inc.
Montville Power LLC Oswego Harbor Power LLC
NEO Chester-Gen LLC Padoma Wind Power, LLC
NEO Corporation Saguaro Power LLC
NEO Freehold-Gen LLC San Juan Mesa Wind Project II, LLC
NEO Power Services Inc. Somerset Operations Inc.
New Genco GP LLC ~~Somerset Power LLC~~
34
Norwalk Power LLC ~~Texas Genco Financing Corp.~~Somerset Power LLC
NRG Affiliate Services Inc. Texas Genco ~~GP, LLC~~Financing Corp.
NRG Arthur Kill Operations Inc. Texas Genco ~~Holdings, Inc.~~GP, LLC
NRG Asia-Pacific Ltd. Texas Genco ~~LP, LLC~~Holdings, Inc.
NRG Astoria Gas Turbine Operations Inc. Texas Genco ~~Operating Services,~~LP, LLC
NRG Bayou Cove LLC Texas Genco Operating Services, LLC
NRG Cabrillo Power Operations Inc. Texas Genco Services, LP
NRG ~~Cabrillo Power~~Cadillac Operations Inc. Vienna Operations, Inc.
NRG ~~Cadillac Operations Inc.~~ ~~Vienna Power LLC~~
~~NRG~~ California Peaker Operations LLC ~~WCP (Generation) Holdings~~Vienna Power LLC
NRG Cedar Bayou Development Company LLC ~~West Coast Power~~WCP (Generation) Holdings LLC
NRG Connecticut Affiliate Services Inc. West Coast Power LLC

32
The non-guarantor subsidiaries include all of NRG’s foreign subsidiaries and certain domestic subsidiaries. NRG conducts much of its business through and derives much of its income from its subsidiaries. Therefore, the Company’s ability to make required payments with respect to its indebtedness and other obligations depends on the financial results and condition of its subsidiaries and NRG’s ability to receive funds from its subsidiaries. Except for NRG Bayou Cove, LLC, which is subject to certain restrictions under the Company’s Peaker financing agreements, there are no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to NRG. In addition, there may be restrictions for certain non-guarantor subsidiaries.

The following condensed consolidating financial information presents the financial information of NRG, ~~Energy, Inc.,~~ the guarantor subsidiaries and the non-guarantor subsidiaries in accordance withRule 3-10 under the ~~SEC’s~~Securities and Exchange Commission’s Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiaries or non-guarantor subsidiaries operated as independent entities.

In this presentation, NRG Energy, Inc. consists of parent company operations. Guarantor subsidiaries and non-guarantor subsidiaries of NRG are reported on an equity basis. For companies acquired, the fair values of the assets and liabilities acquired have been presented on a push-down accounting basis.

3335
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended ~~September 30, 2008~~March 31, 2009

NRG Energy,
NRG Energy,
Guarantor
Non-Guarantor
Inc.
Consolidated
Guarantor Non-Guarantor Inc. Consolidated
(In millions) Subsidiaries Subsidiaries (Note Issuer) Eliminations (a) Balance Subsidiaries Subsidiaries (Note Issuer) Eliminations (a) Balance

Operating Revenues

Total operating revenues $ 2,597 $ 111 $ — $ (18 ) $ 2,690 $    1,566 $    95 $   — $   (3 ) $   1,658

Operating Costs and Expenses

Cost of operations 919 99 (3 ) (18 ) 997 698 68 3 (3 ) 766
Depreciation and amortization 148 7 1 — 156 158 10 1 — 169
General and administrative 16 14 45 — 75 17 3 75 — 95
Development costs 2 2 9 — 13 2 2 9 — 13

Total operating costs and expenses 1,085 122 52 (18 ) 1,241 875 83 88 (3 ) 1,043

Operating Income/(Loss)
1,512 (11 ) (52 ) — 1,449 691 12 (88 ) — 615
Other Income/(Expense)

Equity in earnings/(losses) of consolidated subsidiaries 52 — 897 (949 ) —
Equity in earnings of consolidated subsidiaries 21 — 397 (418 ) —
Equity in earnings of unconsolidated affiliates 1 57 — — 58 1 21 — — 22
Other income/(expense), net 4 11 (22 ) — (7 )
Other income/(loss), net 1 (7 ) 3 — (3 )
Interest expense (46 ) (61 ) (79 ) — (186 ) (48 ) (21 ) (69 ) — (138 )

Total other income/(expense) 11 7 796 (949 ) (135 ) (25 ) (7 ) 331 (418 ) (119 )

Income/(Losses) From Continuing Operations Before Income Taxes
666 5 243 (418 ) 496
Income tax expense 252 1 45 — 298

Income/(Losses) From Continuing Operations Before Income Taxes
1,523 (4 ) 744 (949 ) 1,314
Income tax expense/(benefit) 532 38 (40 ) — 530
Net Income attributable to NRG Energy, Inc.
$    414 $    4 $   198 $   (418 ) $   198

Income/(Losses) From Continuing Operations
991 (42 ) 784 (949 ) 784
Income/(Losses) from discontinued operations, net of income taxes — — — — —

Net Income/(Loss)
$ 991 $(42 ) $ 784 $ (949 ) $784

(a)
All significant intercompany transactions have been eliminated in consolidation.

3436

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING ~~STATEMENTS OF OPERATIONS~~BALANCE SHEETS
March 31, 2009

~~For the Nine Months Ended September 30, 2008~~

Guarantor Non-Guarantor NRG Energy, Inc. Consolidated
(In millions) Subsidiaries Subsidiaries (Note Issuer) Eliminations (a) Balance

ASSETS
Current Assets

Cash and cash equivalents $    2 $   200 $   986 $   — $   1,188
Funds deposited by counterparties 1,275 — — — 1,275
Restricted cash 3 14 — — 17
Accounts receivable, net 360 39 — — 399
Inventory 476 12 — — 488
Derivative instruments valuation 3,862 — — — 3,862
Cash collateral paid in support of energy risk management activities 178 — — — 178
Prepayments and other current assets 89 37 256 (124 ) 258

Total current assets 6,245 302 1,242 (124 ) 7,665

Net property, plant and equipment
10,688 829 27 — 11,544

Other Assets

Investment in subsidiaries 624 — 12,744 (13,368 ) —
Equity investments in affiliates 27 467 — — 494
Capital leases and notes receivable, less current portion 829 403 3,378 (4,207 ) 403
Goodwill 1,718 — — — 1,718
Intangible assets, net 796 17 2 — 815
Nuclear decommissioning trust fund 286 — — — 286
Derivative instruments valuation 1,133 — 15 — 1,148
Other non-current assets 13 5 107 — 125

Total other assets 5,426 892 16,246 (17,575 ) 4,989

Total Assets
$    22,359 $   2,023 $   17,515 $   (17,699 ) $   24,198

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities

Current portion of long-term debt and capital leases $    67 $   232 $   31 $   (67 ) $   263
Accounts payable (781 ) 373 766 — 358
Derivative instruments valuation 2,982 12 6 — 3,000
Deferred income taxes 722 26 (330 ) — 418
Cash collateral received in support of energy risk management activities 1,277 — — — 1,277
Accrued expenses and other current liabilities 90 59 177 (57 ) 269

Total current liabilities 4,357 702 650 (124 ) 5,585

Other Liabilities

Long-term debt and capital leases 2,894 1,046 7,952 (4,207 ) 7,685
Nuclear decommissioning reserve 288 — — — 288
Nuclear decommissioning trust liability 195 — — — 195
Deferred income taxes 633 (159 ) 829 — 1,303
Derivative instruments valuation 284 36 100 — 420
Out-of-market contracts 271 — — — 271
Other non-current liabilities 412 48 277 — 737

Total non-current liabilities 4,977 971 9,158 (4,207 ) 10,899

Total liabilities
9,334 1,673 9,808 (4,331 ) 16,484

3.625% Preferred Stock — — 247 — 247
Stockholders’ Equity
13,025 350 7,460 (13,368 ) 7,467

Total Liabilities and Stockholders’ Equity
$    22,359 $   2,023 $   17,515 $   (17,699 ) $   24,198

3537

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING ~~BALANCE SHEETS~~STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2009

~~September 30, 2008~~

Non- NRG Energy,
Guarantor Guarantor Inc. Consolidated
(In millions) Subsidiaries Subsidiaries (Note Issuer) Eliminations (a) Balance

Cash Flows from Operating Activities

Net income attributable to NRG Energy, Inc. $ 414 $ 4 $ 198 $ (418 ) $ 198
Adjustments to reconcile net income attributable to NRG Energy, Inc. to net cash provided by operating activities:
Equity in earnings of unconsolidated affiliates and consolidated subsidiaries (22 ) (21 ) (397 ) 418 (22 )
Depreciation and amortization 158 10 1 — 169
Amortization of nuclear fuel 10 — — — 10
Amortization of financing costs and debt discount/premiums — 3 6 — 9

Amortization of intangibles and out-of-market contracts (34 ) — — — (34 )
Changes in deferred income taxes and liability for unrecognized tax benefits 116 (11 ) 194 — 299
Changes in nuclear decommissioning liability 6 — — — 6
Changes in derivatives (301 ) (3 ) — — (304 )
Changes in collateral deposits supporting energy risk management activities 312 — — — 312
Gain on sale of assets (1 ) — — — (1 )
Gain on sale of emission allowances (7 ) — — — (7 )

Amortization of unearned equity compensation — — 7 — 7
Changes in option premium collected (270 ) — — — (270 )
Cash provided by/(used by) changes in other working capital (161 ) 38 (110 ) — (233 )

Net Cash Provided/(Used) by Operating Activities
220 20 (101 ) — 139

Cash Flows from Investing Activities

Intercompany loans to from subsidiaries (231 ) — (201 ) 432 —
Investment in consolidated affiliates — — (60 ) 60 —
Capital expenditures (165 ) (68 ) — (233 )
(Increase)/decrease in restricted cash, net 4 (5 ) — — (1 )
Decrease/(increase) in notes receivable — 11 (8 ) — 3
Purchases of emission allowances (35 ) — — — (35 )
Proceeds from sale of emission allowances 8 — — — 8
Investment in nuclear decommissioning trust fund securities (83 ) — — — (83 )
Proceeds from sales of nuclear decommissioning trust fund securities 78 — — — 78
Proceeds from sale of assets 4 — — — 4

Net Cash Used by Investing Activities
(420 ) (62 ) (269 ) 492 (259 )

Cash Flows from Financing Activities

Proceeds from intercompany loans 164 30 238 (432 ) —
Intercompany investments — 60 — (60 ) —
Payment of dividends to preferred stockholders — — (14 ) — (14 )
Receipt from financing element of acquired derivatives 40 — — — 40
Payment of deferred debt issuance costs — (1 ) — — (1 )
Payment of short and long-term debt — (4 ) (205 ) — (209 )

Net Cash Provided by Financing Activities
204 85 19 (492 ) (184 )
Effect of exchange rate changes on cash and cash equivalents — (2 ) — — (2 )

Net Decrease in Cash and Cash Equivalent
4 41 (351 ) — (306 )
Cash and Cash Equivalents at Beginning of Period
(2 ) 159 1,337 — 1,494

Cash and Cash Equivalents at End of Period
$ 2 $ 200 $ 986 $ — $ 1,188

Guarantor
Non-Guarantor
NRG Energy, Inc.
Consolidated

(In millions) Subsidiaries Subsidiaries (Note Issuer) Eliminations (a) Balance

ASSETS
Current Assets

Cash and cash equivalents $ 2 $ 182 $ 1,299 $ — $ 1,483
Restricted cash 1 31 — — 32
Accounts receivable, net 487 44 — — 531
Inventory 444 12 — — 456
Derivative instruments valuation 4,190 — — — 4,190
Cash collateral paid in support of energy risk management activities 544 — — — 544
Prepayments and other current assets 79 35 382 (293 ) 203

Total current assets 5,747 304 1,681 (293 ) 7,439

Net property, plant and equipment
10,752 696 24 — 11,472

Other Assets

Investment in subsidiaries 659 19 10,936 (11,614 ) —
Equity investments in affiliates 26 402 — — 428
Notes receivable and capital lease, less current portion 535 450 2,889 (3,424 ) 450
Goodwill 1,786 — — — 1,786
Intangible assets, net 808 14 — — 822
Nuclear decommissioning trust 333 — — — 333
Derivative instruments valuation 816 — — — 816
Other non-current assets 6 3 125 — 134
Intangible assetsheld-for-sale
3 — — — 3

Total other assets 4,972 888 13,950 (15,038 ) 4,772

Total Assets
$ 21,471 $ 1,888 $ 15,655 $ (15,331 ) $ 23,683

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities

Current portion of long-term debt and capital leases $ 83 $ 90 $ 31 $ (82 ) $ 122
Accounts payable (293 ) 648 12 — 367
Derivative instruments valuation 4,011 10 1 — 4,022
Deferred income taxes — 19 (3 ) — 16
Cash collateral received in support of energy risk management activities 154 — — — 154
Accrued expenses and other current liabilities 422 36 381 (210 ) 629

Total current liabilities 4,377 803 422 (292 ) 5,310

Other Liabilities

Long-term debt and capital leases 2,808 824 7,852 (3,425 ) 8,059
Nuclear decommissioning reserve 320 — — — 320
Nuclear decommissioning trust liability 252 — — — 252
Deferred income taxes 659 (172 ) 596 — 1,083
Derivative instruments valuation 1,089 17 52 — 1,158
Out-of-market contracts
336 — — — 336
Other non-current liabilities 360 65 143 — 568

Total non-current liabilities 5,824 734 8,643 (3,425 ) 11,776

Total liabilities
10,201 1,537 9,065 (3,717 ) 17,086

Minority interest 7 — — — 7
3.625% Preferred Stock — — 247 — 247
Stockholders’ Equity
11,263 351 6,343 (11,614 ) 6,343

Total Liabilities and Stockholders’ Equity
$ 21,471 $ 1,888 $ 15,655 $ (15,331 ) $ 23,683

(a)
All significant intercompany transactions have been eliminated in consolidation.

3638

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF ~~CASH FLOWS~~OPERATIONS

For the ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2008

Non-
NRG Energy,

Guarantor
Guarantor
Inc.
Consolidated

(In millions) Subsidiaries Subsidiaries (Note Issuer) Eliminations (a) Balance

Cash Flows from Operating Activities

Net income $1,354 $     255 $     965 $   (1,609 ) $     965
Adjustments to reconcile net income to net cash provided by operating activities:
Distributions and equity in (earnings)/losses of unconsolidated affiliates and consolidated subsidiaries (260 ) (26 ) (1,347 ) 1,609 (24 )
Depreciation and amortization 454 21 3 — 478
Amortization of nuclear fuel 31 — — — 31
Amortization of financing costs and debt discount — 5 17 — 22
Amortization of intangibles andout-of-market contracts
(226 ) — — — (226 )
Changes in deferred income taxes and liability for unrecognized tax benefits 102 (21 ) 346 — 427
Changes in nuclear decommissioning liability 8 — — — 8
Changes in derivatives (101 ) (9 ) — — (110 )
Changes in collateral deposits supporting energy risk management activities (320 ) — — — (320 )
Loss on disposal and sales of assets 13 — — — 13
Gain on sale of discontinued operations — (273 ) — — (273 )
Gain on sale of emission allowances (52 ) — — — (52 )
Amortization of unearned equity compensation — — 21 — 21
Cash provided by/(used by) changes in other working capital 473 52 (444 ) — 81

Net Cash Provided (Used) by Operating Activities
1,476 4 (439 ) — 1,041

Cash Flows from Investing Activities

Intercompany (loans to)/receipts from subsidiaries (175 ) — 885 (710 ) —
Capital expenditures (444 ) (200 ) (5 ) — (649 )
Increase in restricted cash — (3 ) — — (3 )
Decrease in notes receivable — 35 (15 ) — 20
Purchases of emission allowances (6 ) — — — (6 )
Proceeds from sale of emission allowances 75 — — — 75
Investment in nuclear decomissioning trust fund securities (441 ) — — — (441 )
Proceeds from sales of nuclear decomissioning trust fund securities 434 — — — 434
Proceeds from sale of discontinued operations, net of cash divested — (59 ) 300 — 241
Proceeds from sale of assets 14 — — — 14
Equity investments in unconsolidated affiliates — — (17 ) — (17 )

Net Cash Provided (Used) by Investing Activities
(543 ) (227 ) 1,148 (710 ) (332 )

Cash Flows from Financing Activities

(Payments)/proceeds for intercompany loans (882 ) 208 (36 ) 710 —
Payments for dividends to preferred stockholders — — (41 ) — (41 )
Payment of financing element of acquired derivatives (49 ) — — — (49 )
Payments for treasury stock — — (185 ) — (185 )
Proceeds from issuance of common stock, net of issuance costs — — 8 — 8
Proceeds from sale of minority interest in subsidiary — 50 — — 50
Proceeds from issuance of long-term debt — 20 — — 20
Payments for deferred debt issuance costs — — (2 ) — (2 )
Payments for short and long-term debt — (36 ) (166 ) — (202 )

Net Cash Provided (Used) by Financing Activities
(931 ) 242 (422 ) 710 (401 )
Change in cash from discontinued operations — 43 — — 43
Effect of exchange rate changes on cash and cash equivalents — — — — —

Net Increase in Cash and Cash Equivalent
2 62 287 — 351
Cash and Cash Equivalents at Beginning of Period
— 120 1,012 — 1,132

Cash and Cash Equivalents at End of Period
$      2 $     182 $   1,299 $     — $   1,483

NRG Energy,
Guarantor Non-Guarantor Inc. Consolidated
(In millions) Subsidiaries Subsidiaries (Note Issuer) Eliminations(a) Balance

Operating Revenues

Total operating revenues $   1,201 $   101 $   — $   — $   1,302

Operating Costs and Expenses

Cost of operations 735 67 2 — 804
Depreciation and amortization 153 6 2 — 161
General and administrative 13 3 59 — 75
Development costs — 2 10 — 12

Total operating costs and expenses 901 78 73 — 1,052

Operating Income/(Loss)
300 23 (73 ) — 250
Other Income/(Expense)

Equity in earnings/(losses) of consolidated subsidiaries 72 (18 ) 142 (196 ) —
Equity in losses of unconsolidated affiliates (2 ) (2 ) — — (4 )
Other income, net 1 3 5 — 9
Interest expense (51 ) (21 ) (84 ) — (156 )

Total other income/(expense) 20 (38 ) 63 (196 ) (151 )

Income/(Loss) From Continuing Operations Before Income Taxes
320 (15 ) (10 ) (196 ) 99
Income tax expense/(benefit) 121 (8 ) (59 ) — 54

Income/(Loss) From Continuing Operations
199 (7 ) 49 (196 ) 45
Income from discontinued operations, net of income taxes — 4 — — 4

Net Income/(Loss) attributable to NRG Energy, Inc.
$   199 $   (3 ) $   49 $   (196 ) $   49

(a)
All significant intercompany transactions have been eliminated in consolidation.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING ~~STATEMENTS OF OPERATIONS~~BALANCE SHEETS
December 31, 2008

~~For the Three Months Ended September 30, 2007~~

Non-
Guarantor Guarantor NRG Energy, Consolidated
(In millions) Subsidiaries Subsidiaries Inc. Eliminations(a) Balance

ASSETS
Current Assets

Cash and cash equivalents $   (2 ) $   159 $   1,337 $   — $   1,494
Funds deposited by counterparties — — 754 — 754
Restricted cash 7 9 — — 16
Accounts receivable, net 422 42 — — 464
Inventory 443 12 — — 455
Derivative instruments valuation 4,600 — — — 4,600
Cash collateral paid in support of energy risk management activities 494 — — — 494
Prepayments and other current assets 130 37 278 (230 ) 215

Total current assets 6,094 259 2,369 (230 ) 8,492

Net Property, Plant and Equipment
10,725 791 29 — 11,545

Other Assets

Investment in subsidiaries 651 — 11,949 (12,600 ) —
Equity investments in affiliates 26 464 — — 490
Capital leases and note receivable, less current portion 598 435 3,177 (3,775 ) 435
Goodwill 1,718 — — — 1,718
Intangible assets, net 797 16 2 — 815
Nuclear decommissioning trust fund 303 — — — 303
Derivative instruments valuation 870 — 15 — 885
Other non-current assets 9 4 112 — 125

Total other assets 4,972 919 15,255 (16,375 ) 4,771

Total Assets
$   21,791 $   1,969 $   17,653 $   (16,605 ) $   24,808

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities

Current portion of long-term debt and capital leases $   67 $   235 $   229 $   (67 ) $   464
Accounts payable (1,302 ) 429 1,324 — 451
Derivative instruments valuation 3,976 3 2 — 3,981
Deferred income taxes 503 31 (333 ) — 201
Cash collateral received in support of energy risk management activities 760 — — — 760
Accrued expenses and other current liabilities 507 48 333 (164 ) 724

Total current liabilities 4,511 746 1,555 (231 ) 6,581

Other Liabilities

Long-term debt and capital leases 2,730 1,014 7,729 (3,776 ) 7,697
Nuclear decommissioning reserve 284 — — — 284
Nuclear decommissioning trust liability 218 — — — 218
Deferred income taxes 705 (187 ) 672 — 1,190
Derivative instruments valuation 348 46 114 — 508
Out-of-market contracts 291 — — — 291
Other non-current liabilities 405 44 220 — 669

Total non-current liabilities 4,981 917 8,735 (3,776 ) 10,857

Total liabilities
9,492 1,663 10,290 (4,007 ) 17,438

3.625% Preferred Stock
— — 247 — 247
Stockholders’ Equity
12,299 306 7,116 (12,598 ) 7,123

Total Liabilities and Stockholders’ Equity
$   21,791 $   1,969 $   17,653 $   (16,605 ) $   24,808

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF ~~OPERATIONS~~CASH FLOWS

For the ~~Nine~~Three Months Ended ~~September 30, 2007~~March 31, 2008

NRG Energy,

Guarantor
Non-Guarantor
Inc.
Consolidated

(In millions) Subsidiaries Subsidiaries (Note Issuer) Eliminations (a) Balance

Operating Revenues

Total operating revenues $ 4,326 $     281 $     — $     — $   4,607

Operating Costs and Expenses

Cost of operations 2,346 213 1 — 2,560
Depreciation and amortization 460 17 4 — 481
General and administrative 80 14 140 — 234
Development costs 85 1 22 — 108

Total operating costs and expenses 2,971 245 167 — 3,383
Gain/(loss) on sale of assets 16 — — — 16

Operating Income/(Loss)
1,371 36 (167 ) — 1,240
Other Income/(Expense)

Equity in earnings of consolidated subsidiaries 114 — 768 (882 ) —
Equity in (losses)/earnings of unconsolidated affiliates (2 ) 42 — — 40
Other income, net 7 22 30 (15 ) 44
Refinancing expense — — (35 ) — (35 )
Interest expense (198 ) (63 ) (274 ) 15 (520 )

Total other income/(expense) (79 ) 1 489 (882 ) (471 )

Income From Continuing Operations Before Income Taxes
1,292 37 322 (882 ) 769
Income tax expense/(benefit) 472 (12 ) (160 ) — 300

Income From Continuing Operations
820 49 482 (882 ) 469
Income from discontinued operations, net of income taxes — 13 — — 13

Net Income
$ 820 $     62 $     482 $ $     (882 ) $     482

Non- NRG Energy,
Guarantor Guarantor Inc. Consolidated
(In millions) Subsidiaries Subsidiaries (Note Issuer) Eliminations(a) Balance

Cash Flows from Operating Activities

Net income attributable to NRG Energy, Inc. $   199 $   (3 ) $   49 $   (196 ) $   49

Adjustments to reconcile net income attributable to NRG Energy to net cash provided by operating activities:
Distributions and equity (earnings)/losses of unconsolidated affiliates and consolidated subsidiaries (70 ) 22 (142 ) 196 6
Depreciation and amortization 153 6 2 — 161
Amortization of nuclear fuel 15 — — — 15
Amortization of financing costs and debt discount/premiums — 5 6 — 11
Amortization of intangibles and out-of-market contracts (66 ) — — — (66 )
Changes in deferred income taxes and liability for unrecognized tax benefits (21 ) (19 ) 89 — 49
Changes in nuclear decommissioning liability 9 — — — 9
Changes in derivatives 132 — — — 132
Changes in collateral deposits supporting energy risk management activities (150 ) — — — (150 )
Gain on sale of emission allowances (14 ) — — — (14 )
Amortization of unearned equity compensation — — 7 — 7
Changes in option premium collected 15 — — — 15
Cash provided by/(used by) changes in other working capital, net of dispositions affects 23 (29 ) (158 ) — (164 )

Net Cash Provided/(Used) by Operating Activities
225 (18 ) (147 ) — 60

Cash Flows from Investing Activities

Intercompany (loans to)/receipts from subsidiaries (27 ) — 28 (1 ) —
Capital expenditures (114 ) (48 ) (2 ) — (164 )
Increase in restricted cash, net (10 ) — — — (10 )
Decrease in notes receivable — 9 — — 9
Purchases of emission allowances (1 ) — — — (1 )
Proceeds from sale of emission allowances 31 — — — 31
Investment in nuclear decommissioning trust fund securities (144 ) — — — (144 )
Proceeds from sales of nuclear decommission trust fund securities 135 — — — 135
Proceeds from sale of assets 12 — — — 12

Net Cash Provided/(Used) by Investing Activities
(118 ) (39 ) 26 (1 ) (132 )

Cash Flows from Financing Activities

(Payments)/proceeds for intercompany loans (103 ) 75 27 1 —
Payment of dividends to preferred stockholders — — (14 ) — (14 )
Payment of financing element of acquired derivatives (1 ) — — — (1 )
Payment for treasury stock — — (55 ) — (55 )
Proceeds from issuance of common stock, net of issuance costs — — 2 — 2
Payment of deferred debt issuance costs — — (2 ) — (2 )
Payments for short and long-term debt — (3 ) (151 ) — (154 )

Net Cash Used by Financing Activities
(104 ) 72 (193 ) 1 (224 )
Change in cash from discontinued operations — (6 ) — — (6 )
Effect of Exchange Rate Changes on Cash and Cash Equivalents — 4 — — 4

Net Increase/(Decrease) in Cash and Cash Equivalent
3 13 (314 ) — (298 )
Cash and Cash Equivalents at Beginning of Period
(4 ) 124 1,012 — 1,132

Cash and Cash Equivalents at End of Period
$   (1 ) $   137 $   698 $   — $   834

(a)
All significant intercompany transactions have been eliminated in consolidation.

ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In this discussion and analysis, NRG ~~ENERGY, INC. AND SUBSIDIARIES~~
discusses and explains its financial condition and results of operations, including:

	•		Factors which affect the Company’s business;

	•		NRG’s earnings and costs in the periods presented;

	•		Changes in earnings and costs between periods;

	•		Impact of these factors on NRG’s overall financial condition;

	•		A discussion of new and ongoing initiatives that may affect NRG’s future results of operations and financial condition;

	•		Expected future expenditures for capital projects; and

	•		Expected sources of cash for future operations and capital expenditures.

As you read this discussion and analysis, refer to the Company’s Condensed Consolidated Statements of Operations, which present the results of operations for the three months ended March 31, 2009, and 2008. NRG analyzes and explains the differences between periods in the specific line items of NRG’s Condensed Consolidated Statements of Operations. Also refer to NRG’s 2008 Annual Report on Form 10-K, which includes detailed discussions of various items impacting the Company’s business, results of operations and financial condition, including:

	•		Introduction and Overview section which provides a description of NRG’s business segments;

	•		Strategy section;

	•		Business Environment section, including how regulation, weather, and other factors affect NRG’s business; and

	•		Critical Accounting Policies and Estimates section.

The discussion and analysis below has been organized as follows:

	•		Executive Summary, including introduction and overview, business strategy, and changes to the business environment during the period including regulatory and environmental matters;

	•		Results of operations beginning with an overview of the Company’s consolidated results, followed by a more detailed discussion of those results by operating segment;

	•		Financial condition addressing liquidity position, sources and uses of cash, capital resources and requirements, commitments, and off-balance sheet arrangements; and

	•		Known trends that may affect NRG’s results of operations and financial condition in the future, including the Reliant Retail acquisition and the disposition of the MIBRAG investment.

Executive Summary

~~CONDENSED CONSOLIDATING BALANCE SHEETS~~

~~December 31, 2007~~

Guarantor
Non-Guarantor
NRG Energy
Consolidated

(In millions) Subsidiaries Subsidiaries Inc. Eliminations (a) Balance

ASSETS

Current Assets

Cash and cash equivalents $ — $ 120 $ 1,012 $ — $ 1,132
Restricted cash 1 28 — — 29
Accounts receivable, net 445 37 — — 482
Inventory 439 12 — — 451
Deferred income taxes 139 (18 ) 3 — 124
Derivative instruments valuation 1,034 — — — 1,034
Cash collateral paid in support of energy risk management activities 85 — — — 85
Prepayments and other current assets 97 34 195 (152 ) 174
Current assets — discontinued operations — 51 — — 51

Total current assets 2,240 264 1,210 (152 ) 3,562

Net Property, Plant and Equipment
10,828 470 22 — 11,320

Other Assets

Investment in subsidiaries 610 — 9,787 (10,397 ) —
Equity investments in affiliates 28 397 — — 425
Notes receivable 360 126 3,779 (4,139 ) 126
Capital lease, less current portion — 365 — — 365
Goodwill 1,786 — — — 1,786
Intangible assets, net 859 14 — — 873
Intangible assetsheld-for-sale
14 — — — 14
Nuclear decommissioning trust fund 384 — — — 384
Derivative instruments valuation 150 — — — 150
Other non-current assets 11 1 164 — 176
Non-current assets — discontinued operations — 93 — — 93

Total other assets 4,202 996 13,730 (14,536 ) 4,392

Total Assets
$ 17,270 $ 1,730 $ 14,962 $ (14,688 ) $ 19,274

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities

Current portion of long-term debt and capital leases $ 83 $ 282 $ 184 $ (83 ) $ 466
Accounts payable — trade (695 ) 348 731 — 384
Derivative instruments valuation 916 1 — — 917
Cash collateral received in support of energy risk management activities 14 — — — 14
Accrued expenses and other current liabilities 321 62 145 (69 ) 459
Current liabilities — discontinued operations — 37 — — 37

Total current liabilities 639 730 1,060 (152 ) 2,277

Other Liabilities

Long-term debt and capital leases 3,773 571 7,690 (4,139 ) 7,895
Nuclear decommissioning reserve 307 — — — 307
Nuclear decommissioning trust liability 326 — — — 326
Deferred income taxes 598 (138 ) 383 — 843
Derivative instruments valuation 690 16 53 — 759
Non-currentout-of-market contracts
628 — — — 628
Other non-current liabilities 377 10 25 — 412
Non-current liabilities — discontinued operations — 76 — — 76

Total non-current liabilities 6,699 535 8,151 (4,139 ) 11,246

Total liabilities
7,338 1,265 9,211 (4,291 ) 13,523

3.625% Preferred Stock
— — 247 — 247
Stockholders’ Equity
9,932 465 5,504 (10,397 ) 5,504

Total Liabilities and Stockholders’ Equity
$ 17,270 $ 1,730 $ 14,962 $ (14,688 ) $ 19,274

~~(a)~~ ~~All significant intercompany transactions have been eliminated in consolidation.~~

40

~~NRG ENERGY, INC. AND SUBSIDIARIES~~

~~CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS~~

~~For the Nine Months Ended September 30, 2007~~


~~ITEM 2 —~~	~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

Introduction and Overview

NRG ~~Energy, Inc., or NRG, or the Company,~~ is a wholesale power generation company with a significant presence in major competitive power markets in the ~~United States.~~US. NRG is ~~primarily~~ engaged in the ownership, development, construction and operation of power generation facilities, the transacting in and trading of fuel and transportation services, and the trading of energy, capacity and related products in the ~~United States~~regional markets in the US and select international ~~markets.~~markets where its generating assets are located.

As of ~~September 30, 2008,~~March 31, 2009, NRG had a total global portfolio of 189 active operating fossil fuel and nuclear generation units, at 48 power generation plants, with an aggregate generation capacity of approximately ~~24,020~~24,000 MW, and approximately ~~472~~700 MW under ~~construction.~~construction which includes partners’ interests of 275 MW. In addition to the previous ownership, NRG has ownership interests in two wind farms representing an aggregate generation capacity of 270 MW, which includes partner interests of 75 MW. Within the ~~United States,~~US, NRG has one of the largest and most diversified power generation portfolios in terms of geography, fuel-type and dispatch levels, with approximately ~~22,940~~22,920 MW of fossil fuel and nuclear generation capacity in 177 active generating units at 43 plants. ~~These~~In addition, NRG has ownership interests in two wind farms representing 195 MW of wind generation capacity. All of these power generation facilities combined are primarily located in Texas (approximately ~~10,815 MW)~~11,010 MW, including the 195 MW from the two wind farms), the Northeast (approximately ~~7,020~~7,015 MW), South Central (approximately ~~2,860~~2,845 MW), and ~~the~~ West (approximately 2,130 MW) regions of the ~~United States, with~~US, and approximately 115 MW of additional generation capacity from the Company’s thermal assets.

NRG’s principal domestic power plants consist of a mix of natural gas-, coal-, oil-fired, nuclear and ~~nuclear~~wind facilities, representing approximately ~~46%~~45%, 33%, 16%, 5% and 5%1% of the Company’s total domestic generation capacity, respectively. In addition, ~~15%~~11% of NRG’s domestic generating facilities have dual or multiple fuel capacity, which allows plants to dispatch with the lowest cost fuel ~~option, and~~option.

NRG’s domestic generation facilities consist ~~primarily~~ of intermittent, baseload, intermediate and peaking power generation facilities, the ranking of which is referred to as ~~the~~ Merit Order, and ~~also~~ include thermal energy production plants. The sale of capacity and power from baseload generation facilities accounts for the majority of the Company’s ~~revenues.~~revenues and provides a stable source of cash flow. In addition, NRG’s generation portfolio provides the Company with opportunities to capture additional revenues by selling power during periods of peak demand, offering capacity or similar products to retail electric providers and others, and providing ancillary services to support system reliability.

NRG’s Business Strategy

NRG’s business strategy is designed to enhance the Company’s position as a leading wholesale power generation company in the US. NRG will continue to utilize its asset base as a platform for growth and development and as a source of cash flow generation which can be used for the return of capital to debt and equity holders. The Company’s strategy is ~~reflected~~focused on: (i) top decile operating performance of its existing operating assets and enhanced operating performance of the Company’s commercial operations and hedging program; (ii) repowering of power generation assets at existing sites and development of new power generation projects; and (iii) investment in energy-related new businesses and new technologies associated with the societal and industry imperatives to foster sustainability and combat climate change. This strategy is supported by the Company’s five major initiatives ~~described below. These initiatives~~(FORNRG,RepoweringNRG, econrg, Future NRG and NRG Global Giving) which are designed to ~~enable~~enhance the Company’s competitive advantages in these strategic areas and allow the Company to ~~take advantage of opportunities and~~ surmount the challenges faced by the power ~~industry.~~industry in the coming years. This strategy is being implemented by focusing on the following principles, which are more fully described in Company’s 2008 Annual Report on Form 10-K:

1.	**~~FOR~~~~NRG~~** is a companywide effort designed to increase the return on invested capital, or ROIC, through operational performance improvements to the Company’s asset fleet, along with a range of initiatives at plants and at corporate offices to reduce costs, or in some cases, monetize or reduce excess working capital and other assets. The~~FOR~~NRG accomplishments disclosed in NRG’s SEC filings and press releases include both recurring and one-time improvements measured from a prior base year. For plant operations, the program measures cumulative current year benefits using current gross margins multiplied by the change in baseline levels of certain key performance indicators. The plant performance benefits include both positive and negative results for plant reliability, capacity, heat rate and station service. During 2007, the Company announced the acceleration and planned conclusion of the~~FOR~~NRG 1.0 program by bringing forward the previously announced 2009 target of $250 million to 2008. Improvements in reliability throughout the baseload fleet, coupled with higher gross margins, especially in the Texas region, were the drivers of the~~year-to-date~~ ~~program performance. Through September 2008, the Company has estimated the cumulative value of implemented~~~~FOR~~~~NRG improvements will achieve a value in excess of the established a goal of $250 million by December 31, 2008. The~~~~FOR~~~~NRG 1.0 program was measured from a 2004 baseline, with the exception of the Texas Region where benefits were measured using 2005 as the base year.~~

	~~Beginning in January 2009, the Company will transition to~~~~FOR~~~~NRG 2.0 and target an incremental 100 basis point improvement to the Company’s return on invested capital by 2012. The initial targets for~~~~FOR~~~~NRG 2.0 will be based upon improvements in the Company’s ROIC as measured by increased cash flow. The economic results of~~~~FOR~~~~NRG 2.0 will focus on: (1) revenue enhancement, (2) cost savings, and (3) asset optimization including reducing excess working capital and other assets.~~~~FOR~~~~NRG 2.0 program will measure its progress towards the~~~~FOR~~~~NRG 2.0 goals by using the Company’s 2008 financial results as a baseline, while plant performance calculations will be based upon the average full year plant key performance indicators for years2006-2008.~~

Operational Performance—The Company is focused on increasing value from its existing assets, primarily through the Company’sFORNRG initiative, commercial operations strategy, and maintenance of appropriate levels of liquidity, debt and equity in order to ensure continued access to capital.

Development—NRG is favorably positioned to pursue growth opportunities through expansion of its existing generating capacity and development of new generating capacity at its existing facilities, primarily through the Company’sRepoweringNRG initiative. NRG expects that these efforts will provide one or more of the following benefits: improve heat rates; lower delivered costs; expand electricity production capability; improve the ability to dispatch economically across the regional general portfolio; increase technological and fuel diversity; and reduce environmental impacts, including facilities that either have near zero GHG emissions or can be equipped to capture and sequester GHG emissions. Several of the Company’s originalRepoweringNRG projects or projects commenced under that initiative since its inception may qualify for financial support under the infrastructure financing component of the American Recovery and Reinvestment Act.

~~Repowering~~~~NRG~~ is a comprehensive portfolio redevelopment program designed to develop, construct and operate new multi-fuel, multi-technology, highly efficient and environmentally responsible generation capacity over the next decade. Through this initiative, the Company anticipates retiring certain existing units and adding new generation to meet growing demand in the Company’s core markets, with an emphasis on new capacity that is expected to be supported by long-term hedging programs, including power purchase agreements, or PPAs, and financed with limited or non-recourse project financing.

New Businesses and New Technology—NRG is focused on the development and investment in energy-related new businesses and new technologies where the benefits of such investments represent significant commercial opportunities and create a comparative advantage for the Company, including low or no GHG emitting energy generating sources, such as nuclear, wind, solar thermal, photovoltaic, “clean” coal and gasification, and the retrofit of post-combustion carbon capture technologies. A primary focus of this strategy is supported by the econrg initiative whereby NRG is pursuing investments in new generating facilities and technologies that will be highly efficient and will employ no and low carbon technologies to limit CO₂ emissions and other air emissions. While the Company’s effort in this regard to date has focused on businesses and technologies applicable to the centralized power station, the acquisition of Reliant Retail will put the Company in a position to consider and pursue smart meters and distributed “clean” solutions.

Company-Wide Initiatives—In addition, the Company’s overall strategy is also supported by Future NRG and NRG Global Giving initiatives, which primarily contemplate workforce planning and community investments, respectively.

Finally, NRG will continue to pursue selective acquisitions, joint ventures and divestitures to enhance its asset mix and competitive position in the Company’s core markets. NRG intends to concentrate on opportunities that present attractive risk-adjusted returns. NRG will also opportunistically pursue other strategic transactions, including mergers, acquisitions or divestitures. On March 2, 2009, NRG announced that it entered into an agreement to acquire Reliant Energy, Inc.’s Texas electric retail business operations. SeeNew and On-going Company Initiatives – Reliant Retail Acquisition, hereinafter, for further discussion.

4243

~~econrg~~ represents NRG’s commitment to environmentally responsible power generation. econrg seeks to find ways for NRG to meet the challenges of climate change, clean air and water, and conservation of our natural resources while taking advantage of business opportunities that may inure to NRG as a result of our demonstration and deployment of “green” technologies. Within NRG, econrg builds upon a foundation in environmental compliance and embraces environmental initiatives for the benefit of our communities, employees and shareholders, such as encouraging investment in new environmental technologies, pursuing activities that preserve and protect the environment and encouraging changes in the daily lives of our employees.

~~Future NRG~~ is the Company’s workforce planning and development initiative and represents NRG’s strong commitment to planning for future staffing requirements to meet the on-going needs of the Company’s current operations in addition to the Company’s~~Repowering~~NRG initiatives. Future NRG encompasses analyzing the demographics, skill set and size of the Company’s workforce in addition to the organizational structure with a focus on succession planning, training, development, staffing and recruiting needs. Included under the Future NRG umbrella is NRG University, which provides leadership, managerial, supervisory and technical training programs and individual skill development courses.

~~NRG Global Giving~~ — Respect for the community is one of NRG’s core values. Our Global Giving Program invests NRG’s resources to strengthen the communities where we do business and seeks to make community investments in four FOCUS areas: community and economic development, education, environment and human welfare.

~~NRG’s 2007 Annual Report onForm 10-K~~ ~~includes a detailed discussion of various items impacting its business, results of operations and financial condition. These include:~~


	•	~~Introduction and Overview section which provides a description of NRG’s business segments;~~

	•	~~Strategy section;~~

	•	~~Business Environment section, including how regulation, weather, and other factors affect NRG’s business; and~~

	•	~~Critical Accounting Policies section.~~

Critical accounting policies are the accounting policies that are most important to the portrayal of NRG’s financial condition and results of operations and require management’s most difficult, subjective or complex judgment. NRG’s critical accounting policies include revenue recognition and derivative accounting, income taxes and valuation allowance for deferred taxes, evaluation of assets for impairment and other than temporary decline in value, goodwill and other intangible assets, and contingencies.

~~This discussion and analysis explains the general financial condition and the results of operations for NRG, including:~~


	•	~~factors which affect the business;~~

	•	~~earnings and costs in the periods presented;~~

	•	~~changes in earnings and costs between periods;~~

	•	~~sources of earnings;~~

	•	~~impact of these factors on NRG’s overall financial condition;~~

	•	~~expected future expenditures for capital projects; and~~

	•	~~expected sources of cash for further operations and capital expenditures.~~

As you read this discussion and analysis, refer to the consolidated statements of income which present the results of operations for the three and nine months ended September 30, 2008 and 2007. NRG analyzes and explains the differences between periods in the specific line items of the consolidated statements of income.

~~NRG has organized the discussion and analysis as follows:~~


	•	~~changes to the business environment during the period;~~

	•	~~results of operations beginning with an overview of NRG’s consolidated results, followed by a more detailed discussion of those results by major operating segment;~~

	•	~~financial condition, addressing liquidity, the sources and uses of cash, capital resources and commitments; and~~

	•	~~known trends that will affect NRG’s results of operation and financial condition in the future.~~

~~Changes in Accounting Standards~~

~~See Note 1 to the condensed consolidated financial statements of thisForm 10-Q~~ ~~as found in Item 1 for a discussion of recent accounting developments.~~

Business Environment —– Financial Credit Market Availability and Domestic ~~Recessionary Pressures~~Recession

~~A sharp economic downturn in~~In 2009, the ~~US and overseas during the latter part of 2008 was prompted by a combination of factors:~~nation’s economy continues to experience recessionary factors which include tight credit ~~markets, speculation and fear regarding the health of the US and global financial systems, and weaker economic activity in general prompting fears of an economic recession.~~markets. Power generation companies are capital intensive and, as such, rely on the credit markets for liquidity and for the financing of power generation investments. In addition, economic recessions historically result in lower power demand, power prices, and fuel prices. NRG has a diversified liquidity program, with ~~$3.0~~$3.1 billion in total liquidity, excluding funds deposited by counterparties, and a first and second lien structure that enables significant strategic hedging while reducing requirements for the posting of cash or letters of credit as collateral. NRG expects to continue to manage commodity price volatility through its strategic hedging program, under which the Company expects to hedge revenues and fuel costs. This program should provide the Company with the flexibility to enter into hedges opportunistically, such as when gas prices are increasing, while at the same time protecting NRG against longer-term volatility in the commodity markets. The Company believes that an economic recession is unlikely to have a material impact on the Company’s cash generation in the near term due to the hedged position of its portfolio. NRG transacts with a diversified pool of counterparties and actively manages ~~our~~the Company’s exposure to any single counterparty. See Part 1,I, Item 12—– Liquidity and Capital Resources, and Part 1,I, Item 3—– Quantitative and Qualitative Disclosures about Market Riskfor further discussion.

Unsolicited Exelon Proposal

On October 19, 2008, ~~NRG~~the Company received an unsolicited proposal from Exelon Corporation to acquire all of the outstanding shares of ~~NRG at~~the Company and on November 12, 2008, Exelon announced a ~~fixed exchange ratio~~tender offer for all of ~~0.485~~the Company’s outstanding common stock. On February 26, 2009, Exelon ~~shares for each NRG common share.~~again extended the tender offer, to June 26, 2009. NRG’s Board of Directors, isafter carefully reviewing ~~Exelon’s~~the proposal, ~~with their advisors and will determine~~unanimously concluded that the ~~appropriate response~~proposal was not in ~~due course. As~~the best interests of the ~~date~~stockholders and has recommended that NRG stockholders not tender their shares. In addition, on March 17, 2009 Exelon filed a Preliminary Proxy Statement with the SEC with respect to their proposals for the Company’s 2009 Annual Meeting of Stockholders, which consists of: (i) consideration of Exelon’s four nominees as Class III directors, (ii) consideration of the ~~filing~~expansion of ~~this quarterly report,~~NRG’s board to 19 directors, (iii) if the board expansion is approved, consideration of five additional Exelon nominees; and (iv) consideration of repealing any amendments to the NRG ~~stockholders have been advised to take no action at this time pending the review by~~Bylaws after February 26, 2009. NRG’s Board of ~~Directors.~~

Directors has recommended a vote against each of the proposals.

Environmental Matters

~~Carbon~~Climate Change Update

AtOn March 31, 2009, Representatives Henry Waxman and Edward Markey released draft climate change legislation, titledThe American Clean Energy and Security Act of 2009. This comprehensive draft proposes a multi-sector, market based greenhouse gas cap and trade system starting in 2012 as well as national Renewable Energy Standards, expedited transmission planning and approval and aggressive efficiency measures. While the ~~national~~draft has provisions for both auction and allocation of the allowances, the level of allocation and ~~at various regional and state levels, policies are under development to regulate GHG emissions, including~~the nature of recipients for such allocations have not been defined. The draft further exempts CO₂~~, thereby effectively putting~~ from regulation under New Source Review, or NSR, as a ~~cost on such emissions in order to create financial incentives to reduce them. The Northeast states are furthest along where six~~criteria pollutant, or a hazardous air pollutant under the CAA. In 2008, NRG emitted 60 million metric tonnes of ~~ten participating states held the first~~ CO₂ ~~allowances auction on September 25, 2008. The effective start date is January 1, 2009. California under legislation enacted in 2007 known as AB32, the seven states and four Canadian provinces~~ in the ~~Western Climate Initiative,~~US and ~~the six states in the Midwest GHG Accord~~will continue to ~~develop market based programs for their respective jurisdictions. It is almost certain that all GHG regulatory schemes will encompass power plants. The~~provide input as a leading energy company and member of the US Climate Action Partnership, or USCAP, to achieve final legislation.

If the Waxman-Markey draft legislation or some other federal comprehensive climate change bill were to pass both House of Congress and be enacted into law, the actual impact on the Company’s financial performance ~~will~~would depend on a number of factors, including the overall level of GHG reductions required under any ~~such regulation,~~final legislation, the degree to which offsets may be used for compliance and their price and availability, ~~of offsets,~~ and the extent to which NRG would be entitled to receive ~~GHG~~CO₂ emissions allowances without having to purchase them in an auction or on the open market. ~~Despite current fiscal~~Thereafter, the impact would depend on the level of success of the Company’s multifold strategy, which includes (i) shaping public policy with the objective being constructive and economic concerns, Congressional leaders continue to seek an approach to national climate change legislation that will gain the support necessary to become law. In October 2008, Representatives Bouchereffective federal GHG regulatory policy, and ~~Dingell introduced a climate change discussion draft into Congress that, along with basic cap and trade architecture, offers a menu of options for dealing with a number of important details~~

such as allocations and factors that could affect allowance price. In addition, the climate change discussion draft continues the trend of all major climate legislation in Congress to provide significant support for low carbon investments such as those involved in the Company’s(ii) pursuing itsRepoweringNRG and econrg programs. ~~Information regarding the~~The Company’s ~~carbon~~multifold strategy is discussed in greater detail in Part I, Item 1 — Business, Carbon Update in ~~NRG Energy, Inc.’s 2007~~NRG’s 2008 Annual Report onForm ~~10-K~~ ~~for the fiscal year ended December 31, 2007.~~10-K.

On April ~~2, 2007,~~17, 2009, the ~~US Supreme Court issued~~USEPA released a ~~decision in Massachusetts v. EPA~~proposed endangerment finding that the ~~USEPA has authority under Title II~~mix of ~~the Clean Air Act or CAA to regulate~~six key GHGs, including CO₂ ~~emissions from new motor vehicles. The actual treatment of CO~~₂ ~~under~~, threaten the ~~CAA is contingent upon an official finding by the USEPA on whether these emissions endanger~~ public health and ~~the environment. While such a~~welfare. The proposed endangerment finding ~~based on~~does not include any proposed regulations. This is in response to the Supreme ~~Court~~Court’s decision ~~would be specific~~inMassachusetts v. USEPA, which requires the USEPA to decide under the CAA’s mobile ~~sources, the outcome would also be applicable~~source title whether GHGs contribute to ~~the regulation of~~climate change, and if so, promulgate appropriate regulations. Absent eventual action from Congress on climate change, this finding could ultimately serve as a basis for rulemaking for stationary sources, including electric generating units. On July 30, 2008, the USEPA released an Advance Notice of Proposed Rulemaking, or ANPR, inviting public comment on the benefits and ramifications of regulating GHG emissionslike power plants, under the ~~CAA with comments due to EPA by November 28, 2008. Given this schedule it appears unlikely that there will be any regulation of CO~~₂ ~~under the CAA during the remainder of 2008. At this time, NRG cannot predict the outcome of the ANPR process, any resulting changes to federal regulations, nor the impact on Company operations.~~existing CAA.

Federal Environmental Initiatives

~~On May 18, 2005, the~~A number of regulations are under review by USEPA published the Clean Air Mercury Rule, or CAMR, to permanently cap and reduce mercury emissions from coal-fired power plants. CAMR imposed limits on mercury emissions from new and existing coal-fired plants and created a market-based~~cap-and-trade~~ program to reduce nationwide emissions of mercury. The rule was challenged by New Jersey and ten other states. On February 8, 2008, the US Court of Appeals for the D.C. Circuit vacated USEPA’s rule delisting coal- and oil-fired electric generating units from regulation under CAA § 112, or the Delisting Rule, and CAMR. Power plant emissions are now subject to Section 112 of the CAA which requires installation of maximum achievable control technology, orincluding CAIR, MACT, to reduce emissions. The USEPA plans to develop MACT standards and existing power plants will need to provide plans to meet the new requirements. Certain states in which NRG operates coal plants, such as Delaware, Massachusetts and New York, adopted state implementation plans in lieu of the CAMR federal implementation plan and these state rules remain unchanged. Texas and Louisiana adopted the federal CAMR.

~~On May 12, 2005, the USEPA published the market based Clean Air Interstate Rule, or CAIR. This rule applied to 28 eastern states and the District of Columbia, or D.C., and capped both SO~~₂ ~~and NO~~_x ~~emissions from power plants in two phases; 2010 and 2015 for SO~~₂ ~~and 2009 and 2015 for NO~~_x. CAIR applies to some of the Company’s power plants in New York, Massachusetts, Connecticut, Delaware, Louisiana, Illinois, Pennsylvania, Maryland and Texas. On July 11, 2008, the D.C. Circuit Court ruled that CAIR should be vacated in its entirety. The USEPA petitioned for rehearing~~en banc~~on September 24, 2008. The D.C. Circuit Court must grant or deny the petition over the next few months after which it will be reheard or the USEPA can appeal for a hearing before the Supreme Court. The Court has not yet stayed the rule leaving January 1, 2009 as the effective date for the CAIR annual and seasonal NO_x ~~trading program. NRG’s SO~~₂ ~~and NO~~_x plans are driven primarily by state requirements and consent orders. NRG’s estimate for environmental capital expenditures reflects changes in schedule and design related to the current status of both CAIR and CAMR. The timing and substantive provisions of any ensuing revised or replacement regulations or legislation may alter the composition and rate of spending for environmental retrofits at our facilities.

~~On September 30, 2008, the NRG Texas region held a bank of emissions allowances with a net carrying value of $748 million, consisting of $504 million for SO~~₂ ~~and $244 million for NO~~_x~~. These are classified as long-term intangible assets and are carried at average cost. The D.C. Circuit Court ruling has resulted in a decline in current SO~~₂ ~~market prices. NRG has estimated its SO~~₂ ~~allowance requirement needed for generation based on the new ruling and evaluated any excess SO~~₂ ~~allowances for potential impairment. Variability in generation assumptions and any ensuing regulations or legislation will alter our assumed rate of excess SO~~₂ ~~allowances. NRG does not expect that CAIR and the D.C. Circuit Court ruling will have a material impact on the carrying value of our excess SO~~₂ ~~allowances.~~

~~On March 12, 2008, the USEPA strengthened the primary and secondary ground level ozone~~ National Ambient Air Quality Standards, or NAAQS ~~(eight hour average) from 0.08 ppm~~for ozone, small particle matter, or PM2.5, and the Phase II 316(b) Rule. These rules address air emissions and best practices for units with once-through-cooling. In addition, the USEPA has announced that it is considering new rules regarding the handling and disposition of coal combustion byproducts. While the Company cannot predict the requirements in the final versions nor the ultimate effect that the changing regulations will have on NRG’s business, NRG has prepared an environmental capital expenditure plan in anticipation of such requirements.

The Supreme Court released its decision in the Phase II 316(b) Rule case on April 1, 2009, that the USEPA does have the authority to ~~0.075 ppm. The USEPA plans~~allow a cost-benefit analysis in the evaluation of Best Technology Available, or BTA. This ruling is favorable for the industry and NRG as it improves the USEPA’s ability to ~~finalize ozone non-attainment regions by March 2010 and states would likely submit plans~~include alternatives to ~~come into attainment by 2013. The Company is unable to predict with certainty the impact~~closed-loop cooling in its redraft of the ~~states’ future recommendations on NRG’s operations.~~Phase II 316(b) Rules.

Regional Environmental Initiatives

Northeast Region— ~~On December 20, 2005, 10 northeastern states entered into a Memorandum of Understanding, or MOU, to create the Regional Greenhouse Gas Initiative, or RGGI, to establish acap-and-trade~~ ~~GHG program for~~NRG operates electric ~~generators. Electric~~ generating units located in ~~participating~~Connecticut, Delaware, Maryland, Massachusetts and New York which are subject to RGGI. The RGGI ~~states will have to procure one~~CO₂ cap-and-trade program went into effect on January 1, 2009. An allowance must be surrendered for every US ton of CO₂ emitted with true up for2009-2011 occurring in 2012. ~~NRG units located in Connecticut, Delaware, Maryland, Massachusetts and New York emitted approximately 13 million US tons of CO~~₂~~in 2007. NRG believes that to the extent allowance costs will not be fully reflected in wholesale electricity prices, the direct financial impact~~NRG’s emissions under RGGI was on the ~~Company is likely to be negative as costs~~order of 12 million tonnes in 2008, although 2009 year-to-date emissions are ~~incurred to secure the necessary RGGI allowances and offsets at auction and in the market.~~

tracking lower than first quarter 2008.

Regulatory Matters

As an operator of power plants and a participant in the wholesale markets, NRG is subject to regulation by various federal and state government agencies. In addition, NRG is subject to the market rules, procedures, and protocols of the various ISO markets in which NRG participates. These wholesale power markets are subject to ongoing legislative and regulatory changes. In some of NRG’s regions, interested parties have advocated for material market design changes, including the elimination of a single clearing price mechanism, as well as proposals to re-regulate the markets or require divestiture by generating companies in order to reduce their market share. The Company cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on NRG’s business.

Northeast Region

~~New England~~PJM — — On July 1, 2008, ISO-NE filed proposed revisions to its market rules tariff addressing the compensation for units needed for reliability purposes after June 1, 2010 (the scheduled date for the implementation of the forward capacity market). These rule changes will impact NRG’s units that have operated pursuant to RMR agreements and that seek to delist in the forward capacity auctions such as Norwalk Power’s units 1 and 2 which submitted a delist bid in the first forward capacity auction. On October 28, 2008, FERC determined that units, such as Norwalk Power’s units, that submitted a dynamic delist bid that was rejected by ISO-NE for reliability reasons should be required to operate at their bid amount, not a cost of service rate, notwithstanding mitigation rules that restricted the ability of the units to submit a higher delist bid. As a result, the Norwalk Power units will be compensated at their delist bid of $5.99/kw-mo. for the first FCM capacity year.

On October 20, 2008, Northeast Utilities Service Company, or NU, the parent company of Connecticut Light and Power, filed an application with the Connecticut Siting Council for the Greater Springfield Reliability component of the New England East-West Solution, or NEEWS, transmission project, a significant reinforcement of the 345 kV transmission system. If constructed, the NEEWS line will increase the import capacity into Connecticut by approximately 1,100 MW.

~~New York~~ — On March ~~7, 2008,~~26, 2009, the FERC issued an order accepting in part and rejecting in part a December 12, 2008, PJM proposal to revise the NYISO’s proposed market reforms to the in-city Installed Capacity, or ICAP, market, with only minor modifications. The NYISO proposal retains the existing ICAP market structure, but imposes additional market power mitigation on the current owners of Consolidated Edison’s divested generation units in New York City (which include NRG’s Arthur Kill and Astoria facilities), who are deemed to be pivotal suppliers. Specifically, the NYISO proposal imposes a new reference price on pivotal suppliers and requires bids to be submitted at or below the reference price. The new reference price is derived from the expected clearing price based upon the intersectiondesign of the ~~supply curve~~RPM capacity market, and a February 9, 2009, settlement agreement reached between PJM and various load interests. The revisions will take effect with the ~~ICAP Demand Curve if all suppliers bid as price-takers. The NYISO’s proposed reforms became effective~~next RPM Base Residual Auction for planning year 2012/2013, which is scheduled to take place in May 2009. Several parties have requested rehearing of the March ~~27, 2008.~~26, 2009 order.

~~Texas~~West Region

ERCOT has adopted “Texas Nodal Protocols” that will revise the wholesale market design to incorporate locational marginal pricing (in place of the current ERCOT zonal market). Major elements of the Texas Nodal Protocols include the continued capability for bilateral contracting of energy and ancillary services, a financially binding day-ahead market, resource-specific energy and ancillary service bid curves, the direct assignment of all congestion rents, nodal energy prices for resources, aggregation of nodal to zonal energy prices for loads, congestion revenue rights (including pre-assignment for public power entities), and pricing safeguards. California –The Public Utility Commission of Texas, or PUCT, approved the Texas Nodal Protocols on April 5, 2006, and full implementation of the new market design was scheduled to begin in 2008. On May 20, 2008, ERCOT announced that it would delay the implementation of the Texas Nodal Protocols, and has not provided a new target implementation date.

In May 2008, the ERCOT real-time energy market experienced periods of high prices as a result of limited intervals during which two zonal constraints were simultaneously binding, and this congestion was irresolvable through the dispatch of available resources. In response, ERCOT enacted revised protocols, effective June 9, 2008, for addressing such zonal congestion, providing ERCOT with greater authority to manage such congestion through the use of~~out-of-market~~ mechanisms towards the goal of lowering prices. In addition, on June 17, 2008, ERCOT enacted revisions to its price cap procedures in order to further dampen the volatility and high prices. Thus, it is unlikely that the circumstances contributing to the price spikes of May 2008 will be repeated.

On July 17, 2008, as part of its determination of Competitive Renewable Energy Zones, or CREZ, the PUCT approved a significant transmission expansion plan to provide for the delivery of approximately 18,500 MW of energy from the western region of Texas, primarily wind generation. The schedule for construction of the transmission upgrades (approximately 2,300 miles of new 345 kV lines and 42 miles of new 138 kV lines) will be determined in subsequent PUCT proceedings. If completed as currently approved, the transmission upgrades and associated wind generation could impact wholesale energy and ancillary service prices in ERCOT. The PUCT issued its written order on August 15, 2008.

~~West Region~~

CAISO ~~has indicated that its~~ Market Redesign and Technology ~~Upgrade,~~Update, or MRTU, ~~program will not be implemented before February~~commenced April 1, 2009. Significant components of the MRTU include: (i) locational marginal pricing of energy; (ii) a more effective congestion management system; (iii) a day-ahead market; and (iv) an increase to the existing bid caps. NRG considers these market reforms to generally be a positive development for its assets in the ~~region.~~region, but additional time is needed to assess the impact of MRTU.

Texas Region

On October ~~22,~~6, 2008, FERC issued a definitive order regarding the provision of station power in California. The FERC’s order reaffirmed the right of generators to engage in monthly netting of their station power needs and, further, clarified that local transmission-owning utilities are preempted from imposing state-based charges on such generators. This order should allow the Company to engage in monthly netting and thus avoid buying power at retail for manyas part of its ~~stations and, further, to avoid~~determination of Competitive Renewable Energy Zones, or CREZ, the ~~other charges that the local transmission-owning utilities have been imposing. The Company is proceeding with preparation of a station power plan for submission to the California~~ Public Utility Commission of Texas, or ~~CPUC,~~PUCT, issued its final order approving a significant transmission expansion plan to provide for the delivery of approximately 18,500 MW of energy from the western region of Texas, primarily wind generation – approximately 2,300 miles of new 345 kV lines and ~~expects~~42 miles of new 138 kV lines. In January 2009, Texas Industrial Energy Consumers, a trade organization composed of large industrial customers, appealed PUCT’s CREZ plan in state district court, seeking reversal of the final order. On March 30, 2009, PUCT issued a final order designating the transmission utilities that plan to ~~realize savings~~construct the various CREZ transmission component projects. A large number of separate transmission licensing proceedings will be required prior to construction of the CREZ facilities. If completed as currently approved, the transmission upgrades and associated wind generation could impact wholesale energy and ancillary service prices in ~~operation costs as a result~~ERCOT. As part of ~~this order.~~the normal ERCOT five-year planning process, transmission utilities are also planning other system improvements, 2,800 circuit miles of transmission and more than 17,000 MVA of autotransformer capacity, intended to support increasing power demand and to address transmission congestion.

4745

Changes in Accounting Standards

See Note 1 to the condensed consolidated financial statements of this Form 10-Q as found in Item 1 for a discussion of recent accounting developments.

Consolidated Results of Operations

The following table provides selected financial information for the Company:

Three months ended September 30, Nine months ended September 30,

(In millions except otherwise noted) 2008 2007 Change% 2008 2007 Change%

Operating Revenues

Energy revenue $ 1,373 $ 1,264 9 % $ 3,671 $ 3,255 13 %
Capacity revenue 356 328 9 1,037 890 17
Risk management activities 822 35 N/A 105 44 139
Contract amortization 76 66 15 233 185 26
Thermal revenue 26 27 (4 ) 85 97 (12 )
Other revenues 37 52 (29 ) 177 136 30

Total operating revenues 2,690 1,772 52 5,308 4,607 15
Operating Costs and Expenses

Cost of operations 997 939 6 2,812 2,560 10
Depreciation and amortization 156 160 (3 ) 478 481 (1 )
General and administrative 75 78 (4 ) 233 234 —
Development costs 13 49 (73 ) 29 108 (73 )

Total operating costs and expenses 1,241 1,226 1 3,552 3,383 5
Gain on sale of assets — — — — 16 N/A

Operating income
1,449 546 165 1,756 1,240 42
Other Income/(Expense)

Equity in earnings of unconsolidated affiliates 58 19 205 35 40 (13 )
Other (loss)/income, net (7 ) 14 (150 ) 14 44 (68 )
Refinancing expense — — — — (35 ) N/A
Interest expense (186 ) (169 ) 10 (481 ) (520 ) (8 )

Total other expense (135 ) (136 ) (1 ) (432 ) (471 ) (8 )

Income from Continuing Operations before income tax expense
1,314 410 220 1,324 769 72
Income tax expense 530 145 266 531 300 77

Income from Continuing Operations
784 265 196 793 469 69
Income from discontinued operations, net of income tax expense — 3 N/A 172 13 N/A

Net Income
$ 784 $ 268 193 $ 965 $ 482 100

Business Metrics

Average natural gas price — Henry Hub ($/MMBtu) 9.11 6.24 46 % 9.67 7.02 38 %

Three months ended March 31,
(In millions except otherwise noted) 2009 2008 Change %

Operating Revenues

Energy revenue $   887 $   925 (4 )%
Capacity revenue 260 347 (25 )
Risk management activities 437 (129 ) N/A
Contract amortization 21 69 (70 )
Thermal revenue 34 36 (6 )
Other revenues 19 54 (65 )

Total operating revenues 1,658 1,302 27
Operating Costs and Expenses

Cost of operations (including risk management activities of $68 in 2009) 766 804 (5 )
Depreciation and amortization 169 161 5
General and administrative 95 75 27
Development costs 13 12 8

Total operating costs and expenses 1,043 1,052 (1 )

Operating income
615 250 146
Other Income/(Expense)

Equity in (losses)/earnings of unconsolidated affiliates 22 (4 ) N/A
Other income/(expense), net (3 ) 9 (133 )
Interest expense (138 ) (156 ) (12 )

Total other expenses (119 ) (151 ) (21 )

Income from Continuing Operations before income tax expense
496 99 401
Income tax expense 298 54 452

Income from Continuing Operations
198 45 340
Income from discontinued operations, net of income tax expense — 4 —

Net Income attributable to NRG Energy, Inc.
$   198 $   49 304

Business Metrics

Average natural gas price — Henry Hub ($/MMbtu) 4.58 8.58 (47 )%

N/A — Not Applicable

~~Management’s discussion of the results of operations for the three months ended September 30, 2008 and 2007:~~
~~Operating Revenues~~
Operating revenues, ~~increased $918~~excluding risk management activities, decreased $210 million during the three months ended ~~September~~March 30, ~~2008~~2009, compared to the same period in ~~2007.~~2008.
•
Energy ~~revenues~~revenue— ~~increased $109~~decreased $38 million during the three months ended ~~September 30, 2008~~March 31, 2009, compared to the same period in ~~2007:~~2008:

Texas— energy revenue increased ~~$70~~by $48 million, with ~~$101~~$90 million of this increase driven by higher energy prices, ~~offset by $31 million resulting from lower generation volumes. Energy price increases were due to a more favorable mix of merchant versus contract sales, as well as a 30% increase in merchant prices~~ partially offset by $42 million of reduced generation. During both 2008 and 2009, the average realized merchant prices were higher than the average contract prices. A higher volume of MWh sold under the merchant market yielded a ~~14% decrease~~higher average realized energy price, even though the average realized merchant price decreased by 11%. In addition, the 22% increase in contract price further contributed to the rise in average energy prices. Coal plant generation ~~increased~~decreased by ~~1%, while~~7% and gas plant generation decreased by ~~26%~~40%, ~~attributable to~~partially offset by new generation from the ~~effects of hurricane Ike~~recently constructed Elbow Creek wind farm. Coal plant generation was impacted by a 51% decrease in ~~September 2008.~~average natural gas prices, increased production costs, and increased wind generation which moved the coal units further up the bid stack.

Northeast— ~~increased $5~~energy revenue decreased by $83 million, with ~~$49~~$32 million driven by ~~higher~~lower energy prices ~~offset by a $44~~and $63 million ~~decrease~~ attributable to a reduction in ~~generation. Higher~~generation offset by an $11 million increase from higher net contract revenue. Merchant energy prices were lower by an average of 12%. The lower energy prices reduced the Company’s net cost incurred to meet obligations under load serving contracts in the PJM market. Generation decreased 27% primarily due to reduced generation caused by a 26% decrease in coal generation and a 48% decrease in New York City gas generation. The decrease in coal generation was caused by several factors including a planned 20 day outage at the western New York facilities, a transmission line outage in western New York and weakened power demand for power at the Indian River and Somerset facilities. The decrease in gas generation is largely the result of fewer run hours for voltage support at the Arthur Kill facility.

South Central— energy revenue decreased by $4 million due to an ~~average 19% rise in~~unfavorable mix of contract versus merchant ~~prices offset by lower contract~~energy revenue. Contract revenue ~~of $11~~declined $13 million ~~driven by higher costs required to service the PJM contracts,~~ as a result of ~~the~~a contract expiration with a regional utility. This decrease was offset by an $11 million increase in merchant energy revenue from the sale of available generation and the increased use of the region’s tolled facility into the merchant market ~~energy~~at lower average prices. ~~Generation~~

•

Capacity revenue —decreased ~~12%~~$87 million during the three months ended March 31, 2009, compared to the same period in 2008:

o		Texas— capacity revenue decreased by $71 million due to a ~~cooler summer in 2008 as compared to 2007.~~lower proportion of baseload contracts which contained a capacity component.

o	~~South Central~~~~— increased $19 million, attributable to higher merchant energy revenues, reflecting a 40% rise in on-peak power prices combined with a 19% increase in merchant energy MWh sold.~~

o	~~West~~~~— increased $11 million due to the dispatch of the El Segundo plant outside of its tolling agreement in 2008. In 2007, no such dispatch occurred.~~


	•	~~Capacity revenues —~~~~increased $28 million during the three months ended September 30, 2008 compared to the same period in 2007:~~


o	~~Texas~~~~— increased $39 million due to a greater proportion of base-load contracts, which contain a capacity component.~~

o	Northeast— capacity revenue decreased $9by $14 million as lower capacity prices in the NYISO and PJM markets were partially offset by higher capacity prices in the NEPOOL ~~markets.~~market.

o		South Central— capacity revenue increased by $11 million. A new contract with a regional utility and a rise in the PJM market prices for the region’s Rockford plant contributed to the increase in capacity revenue of $9 million and $3 million, respectively.

o		West— capacity revenue decreased by $9 million due to the expiration of a two year tolling agreement at the El Segundo facility.

	•		Contract amortization revenue— resulting from the Texas Genco acquisition decreased by $48 million due to the lower volume of contracted energy in the three months ended March 31, 2009, as compared to the same period in 2008.

	•		Other revenues— decreased ~~$15~~by $35 million driven by lower gas and coal trading of $23 million, a decline in emissions revenues of $7 million and reduced ancillary revenues of $6 million.

Cost of energy— decreased $117 million during the three months ended ~~September 30, 2008~~March 31, 2009, compared to the same period in ~~2007, driven by reduced activity~~2008 due to:

Texas— cost of energy decreased $85 million due to lower natural gas, coal, and purchased energy costs. Natural gas costs decreased $48 million, reflecting a 51% decline in ~~trading~~per MMBtu average natural gas prices and a 40% decrease in gas-fired generation. Coal costs decreased $12 million as the prior period included a $15 million loss reserve related to a coal ~~of $31 million,~~contract dispute offset by a ~~$12~~$3 million increase in delivered coal costs. Purchased energy decreased $14 million as the Company’s generating assets provided more energy to fulfill its obligation. Ancillary service costs decreased by $11 million due to a decrease in purchased ancillary ~~revenue.~~services costs incurred to meet contract obligation. Nuclear fuel expenses decreased by $5 million.

~~Risk management activities~~Northeast— ~~revenues~~cost of energy decreased $46 million due to a $33 million reduction in natural gas costs and a $21 million reduction in coal costs. Natural gas costs decreased due to 48% lower New York City gas generation and 38% lower average prices. Coal costs decreased due to 26% lower coal generation. These decreases were offset by a $5 million increase in costs related to RGGI which became effective in 2009 and a $4 million increase in average oil costs.

	o		South Central— cost of energy increased $14 million due to an increase in purchased energy reflecting higher gas costs resulting from ~~risk management activities include economic hedges that did not qualify~~a higher proportion of generation sourced from region’s tolled facility and higher capacity payments on such tolled facility. The tolling arrangement in 2009 was for ~~cash flow hedge accounting, ineffectiveness on cash flow hedges, and trading activities. Such revenues~~three months compared to one month in 2008.

	o		West— cost of energy increased ~~by $787~~$2 million due to a write-down to net realizable value of fuel oil inventory no longer used in the production of energy.

•

Other operating costs —increased $11 million during the three months ended ~~September 30, 2008~~March 31, 2009, compared to the same period in ~~2007. The breakdown of changes by region is as follows:~~2008 due to increased operating and maintenance expenses.

Three months ended September 30, 2008 Three months ended September 30, 2007

South
South

(In millions) Texas Northeast Central Total Texas Northeast Central Total

Net gains/(losses) on settled positions, orfinancial revenues
$ 3 $ 22 $ (4 ) $ 21 $ 15 $ 13 $ 1 $ 29

Mark-to-market results

Reversal of previously recognized unrealized gains on settled positions related to economic hedges (5 ) (2 ) — (7 ) (15 ) (2 ) — (17 )
Reversal of previously recognized unrealized gains on settled positions related to trading activity — (6 ) (3 ) (9 ) (1 ) 3 (5 ) (3 )
Net unrealized gains/(losses) on open positions related to economic hedges 590 201 — 791 1 9 — 10
Net unrealized gains/(losses) on open positions related to trading activity (12 ) 8 30 26 (4 ) 5 15 16

Subtotalmark-to-market results
573 201 27 801 (19 ) 15 10 6
Total gain/(loss) $ 576 $ 223 $ 23 $ 822 $ (4 ) $ 28 $ 11 $ 35

     Risk Management Activities
     Risk management activities include economic hedges that did not qualify for cash flow hedge accounting, ineffectiveness on cash flow hedges, and trading activities. Total derivative gains increased by $498 million during the three months ended March 31, 2009, compared to the same period in 2008. The breakdown of changes by region follows:

Three months ended March 31, 2009 Three months ended March 31, 2008
South South
(In millions) Texas Northeast Central West Thermal Total Texas Northeast Central Total

Net gains/(losses) on settled positions, orfinancial income
$   29 $   56 $   10 $   (2 ) $   1 $   94 $   (2 ) $   10 $   4 $   12

Mark-to-market results

Reversal of previously recognized unrealized gains on settled positions related to economic hedges (8 ) (7 ) — — (1 ) (16 ) (7 ) (3 ) — (10 )
Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity (29 ) (14 ) (26 ) — — (69 ) 1 1 (7 ) (5 )
Net unrealized gains/(losses) on open positions related to economic hedges 204 153 (5 ) (1 ) 2 353 (113 ) (29 ) — (142 )
Net unrealized gains/(losses) on open positions related to trading activity 2 (1 ) 6 — — 7 17 (17 ) 16 16

Subtotal mark-to-market results
169 131 (25 ) (1 ) 1 275 (102 ) (48 ) 9 (141 )

Total derivative gain/(loss) 198 187 (15 ) (3 ) 2 369 (104 ) (38 ) 13 (129 )

Total derivative gain/(loss) included in revenues
263 182 (7 ) (3 ) 2 437 (104 ) (38 ) 13 (129 )
Total derivative gain/(loss) included in cost of operations
$   (65 ) $   5 $   (8 ) $   — $ — $   (68 ) $   — $   — $   — $   —

NRG’s ~~third~~first quarter ~~2008~~2009 gain is comprised of ~~$801~~$275 million ofmark-to-market gains and ~~$21~~$94 million in settled gains, or financial ~~revenue.~~income. Of the ~~$801~~$275 million ofmark-to-market gains, $7$16 million loss represents the reversal ofmark-to-market gains recognized on economic hedges and $9$69 million loss represents the reversal ofmark-to-market gains recognized on trading activity during ~~2007.~~2008. Both of these losses ultimately settled as financial ~~revenues~~income during ~~2008.~~2009. The ~~$791~~$353 million gain from economic hedge positions ~~included a $439~~includes $217 million recognized in earnings from previously deferred amounts in OCI as the Company discontinued cash flow hedge accounting for certain 2009 transactions in Texas and New York due to lower expected generation, $132 million increase in value ofin forward sales of electricity and fuel due to lower forward power and gas prices, and a ~~$352~~$4 million gain primarily from hedge accounting ineffectiveness related to gas trades in the Texas region which was driven by decreasing forward gas prices while forward power prices decreased at a slower pace. The Company recognized a derivative loss

4948

of $29 million resulting from discontinued NPNS designated coal purchases due to expected lower coal consumption and accordingly the Company could not assert taking physical delivery of coal purchase transactions under NPNS designation. This amount is included in the Company’s cost of operations.

Since these hedging activities are intended to mitigate the risk of commodity price movements on revenues and cost of energy, the changes in such results should not be viewed in isolation, but rather should be taken together with the effects of pricing and cost changes on energy ~~revenues.~~revenue and costs. During and prior to ~~2007,~~2008, NRG hedged a portion of the Company’s ~~2007~~2008 and ~~2008~~2009 generation. During the ~~third~~first quarter ~~2007 and 2008~~2009, the settled and forward prices of electricity and natural gas ~~have~~ decreased resulting in the recognition of realized gains and unrealizedmark-to-market ~~gains.~~ gains, while in the first quarter 2008, increasing prices of electricity and natural gas resulted in recognition of unrealized mark-to-market losses.

~~Cost of Operations~~Depreciation and Amortization

~~Cost of operations~~NRG’s depreciation and amortization expense increased ~~$58~~by $8 million ~~during~~for the three months ended ~~September 30, 2008~~March 31, 2009, compared to the same period in ~~2007.~~2008. The increase was due to depreciation on the baghouse projects in western New York and the Elbow Creek project which came online in 2009.


	•	~~Cost of energy~~~~— increased $45 million during the three months ended September 30, 2008 compared to the same period in 2007 due to:~~


	o	~~Texas~~— increased $8 million due to higher natural gas, coal, and ancillary service costs, offset by lower nuclear fuel expense and amortized contract costs. Natural gas cost increased $22 million, reflecting a 45% rise in per MMBtu average natural gas prices, offset by a 26% decrease in gas-fired generation. Coal costs increased $3 million due to higher coal prices. Ancillary service costs rose $11 million due to increased purchases to meet contract obligations and a rise in ancillary service costs incurred by ERCOT. Nuclear fuel expense decreased $15 million as amortization of nuclear fuel inventory established under Texas Genco purchase accounting ended in 2008. Amortized contract costs decreased $11 million as amortization of water supply contracts established under Texas Genco purchase accounting ended in 2007.

	o	~~Northeast~~— decreased $1 million as a $15 million reduction in natural gas costs and a $2 million reduction in oil costs were offset by a $16 million increase in coal costs. Natural gas cost decreased due to 26% lower generation offset by higher average prices. Coal costs increased due to higher prices and fuel transportation surcharges offset by 4% lower coal generation.

	o	~~South Central~~— increased $25 million due to a $14 million increase in purchased energy reflecting higher gas costs, and a $12 million increase in natural gas costs as certain gas plants ran extensively to support transmission system stability during hurricane Gustav.

	o	~~West~~~~— increased $10 million due to the dispatch of the El Segundo plant outside of the tolling agreement in 2008. In 2007, no such dispatch occurred.~~


	•	~~Other operating costs —~~increased $13 million during the three months ended September 30, 2008 compared to the same period in 2007, due to increased operating and maintenance expenses, as well as higher diesel and chemical costs in the Texas region.

~~Development Costs~~General and Administrative Expenses

~~NRG’s development costs arise from~~~~Repowering~~~~NRG projects~~General and ~~were $13~~administrative expenses increased by $20 million for the three months ended ~~September 30, 2008, a decrease of $36 million when~~March 31, 2009, compared to the same period in ~~2007:~~2008. The increase is due to:


	•		~~Texas STP units 3~~Acquisition and ~~4 projects~~integration costs — ~~— No development expense was reflected in results of operations for the third quarter 2008 period as NRG began~~increased $12 million due to ~~capitalize STP units 3 and 4 development~~ costs incurred ~~after January 1, 2008 following~~related to the ~~NRC’s docketing~~acquisition of ~~the Company’s Combined Operating License Application, or COLA, in late 2007. The Company recorded $35 million in development expenses during the same period in 2007.~~Reliant Retail.

	•		~~Wind projects~~Consultant costs —~~— the Company incurred $4~~increased $5 million ~~in development costs~~as a result of efforts related to ~~wind projects in Texas~~Exelon’s exchange offer and ~~California which is a $1 million decrease from the same period in 2007.~~proxy contest.

	•		~~Other projects~~Wage and benefits expense —~~— the Company incurred $9 million in development costs related to other domestic~~~~Repowering~~~~NRG projects which is consistent with the same period in 2007.~~increased $3 million.

Equity in Earnings of Unconsolidated Affiliates

NRG’s equity earnings from unconsolidated affiliates increased by ~~$39~~$26 million for the three months ended ~~September 30, 2008~~March 31, 2009, compared to the same period in ~~2007. This increase was due to~~2008. During 2009, Sherbino recognized a ~~$41~~$5 millionmark-to-market unrealized gain whereas in 2008 Sherbino recognized an $18 million mark-to-market loss on a ~~forward contract for~~ natural gas swap executed to hedge ~~the~~its future power ~~generation of Sherbino.~~generation. Additionally in 2009, the Company’s share in NRG Saguaro LLC earnings increased by $3 million.

Other ~~(Loss)/Income,~~Income/(Expense), Net

NRG’s other ~~(loss)/income~~income/(expense) decreased by ~~$21~~$12 million for the three months ended ~~September 30, 2008~~March 31, 2009, compared to the same period in ~~2007.~~2008. The ~~Company recorded an additional $19~~2009 amount includes a $9 million ~~impairment charge in~~mark-to-market unrealized loss on a forward contract for foreign currency executed to hedge the ~~third quarter 2008 to restructure distressed investments in commercial paper, as previously disclosed in 2007, reducing its carrying value to $10 million.~~sale proceeds from the MIBRAG sale.

Interest Expense

NRG’s interest expense ~~increased~~decreased by ~~$17~~$18 million for the three months ended ~~September 30, 2008~~March 31, 2009, compared to the same period in ~~2007.~~2008. This ~~increase~~decrease was due to lower debt balance and lower interest rate on the $45 million payment made to CS for the benefit of CSF I in August 2008 to early settle the embedded derivative in the Company’s CSF I notes and preferred interests. This increase was offset by decreases due to interest savings from the $300 million prepayment in December 2007 and an additional payment of $143 million in March 2008unhedged portion of the Term ~~B loan in connection with~~Loan Facility and the ~~mandatory offer under~~fair value hedge of the Senior ~~Credit Facility accompanied by~~Notes. In addition there was a ~~reduction on the variable~~decrease of $4 million as a result of higher interest ~~rates on long-term debt. Interest~~ capitalized onRepoweringNRG projects under ~~construction also contributed to this decrease.~~construction.

Income Tax Expense

NRG’s income tax expense increased by ~~$385~~$244 million for the three months ended ~~September 30, 2008~~March 31, 2009, compared to the same period in ~~2007.~~2008. The effective tax rate was ~~40.3%~~60.0% and ~~35.4%~~54.5% for the three months ended ~~September 30,~~March 31, 2009, and 2008, ~~and 2007,~~ respectively. The increase in income tax expense was primarily due to an increase in income.

~~The increase in income tax expense was due to:~~

~~The~~ For the three months ended March 31, 2009 and 2008, NRG’s overall effective ~~income~~ tax rate ~~may vary from period~~on continuing operations was different than the statutory rate of 35% primarily due to ~~period depending on, among other factors, the geographic~~state income taxes and ~~business mix of earnings and losses and changes~~an increase in valuation ~~allowances~~allowance as a result of capital losses generated in ~~accordance with SFAS 109. These factors and others, including~~ the ~~Company’s history of pre-tax earnings and losses,~~quarter for which there are ~~taken into account in assessing~~no projected capital gain or available tax planning strategies. In addition, for the ~~ability to realize deferred~~three months ended March 31, 2008, NRG’s overall effective tax ~~assets.~~rate on continuing operations was impacted by a taxable dividend from foreign operations.

Income from Discontinued Operations, Net of Income Tax Expense

Discontinued operations included ITISA results for the three months ended September 30, 2007. NRG classifies as discontinued operations the income from operations and gains/losses recognized on the sale of projects that were sold or have met the required criteria for such classification pending final disposition. For the three months ended ~~September 30, 2007,~~March 31, 2008, NRG recorded income from discontinued operations, net of income tax expense, of $3$4 million. NRG closed the sale of ITISA during the second quarter 2008.

~~Management’s discussion of the results of operations for the nine months ended September 30, 2008 and 2007:~~

~~Operating Revenues~~

~~Operating revenues increased $701 million during the nine months ended September 30, 2008 compared to the same period in 2007.~~


	•	~~Energy revenues~~ ~~— increased $416 million during the nine months ended September 30, 2008 compared to the same period in 2007:~~


	o	~~Texas~~— increased $291 million, was driven by higher prices, as generating volumes were essentially unchanged. The price variance was attributable to a more favorable mix of merchant versus contract sales, as well as a 38% increase in merchant prices partially offset by a 14% decrease in contract energy prices. Total generation was largely unchanged at 36 million MWh. The mix of generation however did change with a 3% higher generation from the nuclear plant and a less than 1% rise in generation from coal plants. This mix was offset by a 7% reduction in gas plant generation, attributable to the effects of hurricane Ike in September 2008.

	o	~~Northeast~~— increased $28 million, with $57 million of the increase driven by higher energy prices, offset by $29 million due to reduced generation. The increase due to energy prices reflects an average 12% rise in merchant energy prices offset by lower contract revenue, driven by higher costs required to service the PJM contracts, as a result of the increase in market energy prices. The decline due to generation was driven by a net 3% reduction in the region’s generation, due to a cooler summer and warmer winter in 2008 compared to 2007.

	o	~~South Central~~— increased $61 million, attributable to $57 million higher merchant energy revenues. The growth in merchant energy revenues reflects a 35% rise in merchant MWh sold, as a 6% decrease in contract load MWh allowed more sales to the merchant market at higher prices.

	o	~~West~~~~— increased $23 million due to the dispatch of the El Segundo plant outside of the tolling agreement in 2008. In 2007, no such dispatch occurred.~~


	•	~~Capacity revenues~~~~— increased $147 million during the nine months ended September 30, 2008 compared to the same period in 2007:~~


	o	~~Texas~~~~— increased $93 million due to a greater proportion of base-load contracts, which contain a capacity component.~~

	o	~~Northeast~~~~— increased $26 million reflecting higher capacity revenues in the PJM and NEPOOL markets.~~

	o	~~South Central~~— increased $11 million due to new peak loads set by the region’s cooperative customers which resulted in $6 million of additional capacity payments and increased RPM capacity payments of $5 million from the PJM market.

	o	~~West~~~~— increased $10 million due to a tolling arrangement at Long Beach plant.~~


	•	~~Contract amortization revenues~~— increased $48 million during the nine months ended September 30, 2008 compared to the same period in 2007 due to the volume of contracted energy affected by a greater spread between contract prices and market prices used in the Texas Genco purchase accounting.


	•	~~Other revenues~~— increased by $41 million during the nine months ended September 30, 2008 compared to the same period in 2007. The increases arose from greater ancillary services revenue of $30 million and increased activity in the trading of emission allowances and carbon financial instruments of $21 million. These increases were offset by $12 million in lower gas and coal trading activities.

	•	~~Risk management activities~~— revenues from risk management activities include economic hedges that did not qualify for cash flow hedges, ineffectiveness on cash flow hedge accounting and trading activities. Such revenues increased by $61 million during the nine months ended September 30, 2008 compared to the same period in 2007. The breakdown of changes by region is as follows:

Nine months ended September 30, Nine months ended September 30,
2008 2007

South
South

(In millions) Texas Northeast Central Total Texas Northeast Central Total

Net gains/(losses) on settled positions, orfinancial revenues
$ (47 ) $ (2 ) $ (4 ) $ (53 ) $ 31 $ 49 $ 5 $ 85

Mark-to-market results

Reversal of previously recognized unrealized gains on settled positions related to economic hedges (21 ) (11 ) — (32 ) (69 ) (40 ) — (109 )
Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity 1 (7 ) (14 ) (20 ) — (9 ) (14 ) (23 )
Net unrealized gains/(losses) on open positions related to economic hedges 95 58 — 153 39 15 — 54
Net unrealized gains/(losses) on open positions related to trading activity 25 1 31 57 1 8 28 37

Subtotalmark-to-market results
100 41 17 158 (29 ) (26 ) 14 (41 )
Total gain/(loss) $ 53 $ 39 $ 13 $ 105 $ 2 $ 23 $ 19 $ 44

~~NRG’s 2008 gain is comprised of $158 million ofmark-to-market~~ ~~gains and $53 million in settled losses, or financial revenue. Of the $158 million ofmark-to-market~~ ~~gains, $32 million represents the reversal ofmark-to-market~~ ~~gains recognized on economic hedges and $20 million represents the reversal ofmark-to-market~~ gains recognized on trading activity during 2007. Both of these losses ultimately settled as financial revenues during 2008. The $153 million gain from economic hedge positions included a $180 million increase in value of forward sales of electricity and fuel due to higher forward power and gas prices and a $27 million loss primarily from hedge accounting ineffectiveness related to gas trades in the Texas region which was driven by increasing forward gas prices while forward power prices rose at a slower pace.
Since these hedging activities are intended to mitigate the risk of commodity price movements on revenues the changes in such results should not be viewed in isolation, but rather should be taken together with the effects of pricing and cost changes on energy revenues. During and throughout 2007, NRG hedged a portion of the Company’s 2007 and 2008 generation. Since that time, the settled and forward prices of electricity and natural gas have decreased, resulting in the recognition of unrealized~~mark-to-market~~ ~~forward gains. In 2007, NRG recognized forwardmark-to-market~~ ~~losses as forward prices of electricity increased relative to its forward positions.~~

53

~~Cost of Operations~~

~~Cost of operations increased $252 million during the nine months ended September 30, 2008 compared to the same period in 2007.~~


	•	~~Cost of energy~~~~— increased $260 million during the nine months ended September 30, 2008 compared to the same period in 2007 due to:~~


	o	~~Texas~~— increased $132 million due to increases in natural gas costs, coal costs and ancillary services cost, offset by reductions in nuclear fuel expenses and amortization of contracts cost. The $136 million rise in natural gas costs was due to an increase of average natural gas prices, offset by a 7% decrease in gas-fired generation. The $16 million increase in coal costs was a result of the recognition of a settlement related to a coal contract dispute and higher coal prices. The $19 million increase in ancillary services and other costs was the result of higher purchased ancillary services and increased ERCOT ISO fees. Amortized contracts costs decreased by $31 million as the amortization of water supply contracts established under Texas Genco purchase accounting ended in 2007. Nuclear fuel expense decreased by $11 million as amortization of nuclear fuel inventory established under Texas Genco purchase accounting ended in early 2008.

	o	~~Northeast~~— increased $51 million due to $54 million higher coal costs and $20 million higher natural gas costs, offset by $23 million reduced oil costs. Coal costs increased due to 4% higher generation, as well as higher coal prices and fuel transportation surcharges. Natural gas costs increased due to higher natural gas prices, despite 14% lower generation. Oil costs decreased due to lower oil-fired generation.

	o	~~South Central~~— increased $43 million due to a $7 million rise in coals costs resulting from an increase in fuel transportation surcharges, a $12 million rise in natural gas costs as the region’s peaker plants ran extensively to support transmission system stability after hurricane Gustav, and an $18 million increase in purchased energy, reflecting higher natural gas costs for tolling contracts.

	o	~~West~~~~— increased $23 million due to the dispatch of the El Segundo plant outside of the tolling agreement in 2008. In 2007, no such dispatch occurred.~~


	•	~~Other operating costs —~~~~decreased $8 million during the nine months ended September 30, 2008 compared to the same period in 2007. This decrease was due to:~~


	o	~~Texas~~— increased $20 million due to higher operating and maintenance expenses, increased chemical and diesel costs at the region’s fossil plants, STP equipment retirements and refueling outage, and the timing of annual outages at the WA Parish and Limestone plants.

	o	~~Northeast —~~decreased $19 million due to a $16 million decrease in operating and maintenance expenses and a $7 million decrease in property taxes. The decrease in operating and maintenance expenses was the result of less outage work at the Arthur Kill, Huntley and Norwalk plants. The reduction in property taxes was due to property tax credits received in 2008.

~~Development Costs~~

~~NRG’s development costs that rose from~~~~Repowering~~~~NRG projects were $29 million for the nine months ended September 30, 2008, which is a decrease of $79 million when compared to the same period in 2007:~~


	•	~~Texas STP units 3 and 4 projects~~— the Company recorded $7 million of income during the nine months ended September 30, 2008, compared to $74 million in development expenses during the same period in 2007. The 2008 activity reflects an April 2008 reimbursement under a partnership agreement for development costs incurred in 2007. No development expense is reflected in results of operations for the nine months ended September 30, 2008 period as NRG began to capitalize STP units 3 and 4 development costs incurred after January 1, 2008 following the NRC’s docketing of the Company’s Combined Operating License Application, or COLA, in late 2007.

	•	~~Wind projects~~~~— the Company incurred $13 million in development costs related to Texas wind projects, which is a $1 million increase from the same period in 2007.~~


	•	~~Other projects~~~~— the Company incurred $23 million in development costs related to other domestic~~~~Repowering~~~~NRG projects which is a $1 million increase from the same period in 2007.~~

~~Gain on Sale of Assets~~

The Company reported no gains on sales of assets for the nine months ended September 2008. For the nine months ended September 30, 2007, NRG’s gain on the sale of assets was $16 million. On January 3, 2007, NRG completed the sale of the Company’s Red Bluff and Chowchilla II power plants resulting in a pre-tax gain of $18 million.

~~Equity in Earnings of Unconsolidated Affiliates~~

NRG’s equity earnings from unconsolidated affiliates decreased by $5 million for the nine months ended September 30, 2008 compared to the same period in 2007. This decrease was due to a $9 million~~mark-to-market~~ ~~unrealized loss on natural gas swap executed to hedge the future power generation of Sherbino.~~

~~Other (Loss)/Income, Net~~

NRG’s other (loss)/income decreased by $30 million for the nine months ended September 30, 2008 compared to the same period in 2007. The Company recorded an additional $22 million impairment charge in 2008 to restructure distressed investments in commercial paper, as previously disclosed in 2007, reducing its carrying value to $10 million. In addition, the 2008 results reflect reduced interest income of $32 million from lower market interest rates on cash deposits.

~~Refinancing Expense~~

Refinancing expense decreased by $35 million for the nine months ended September 30, 2008 compared to the same period in 2007. On June 8, 2007, NRG completed a $4.4 billion refinancing of the Company’s Senior Credit Facility, resulting in a charge of $35 million from the write-off of deferred financing costs as the lenders for 45% of the Term B loan either exited the financing or reduced their holdings and were replaced by other institutions.

~~Interest Expense~~

NRG’s interest expense decreased by $39 million for the nine months ended September 30, 2008 compared to the same period in 2007. This decrease was due to interest savings from the $300 million prepayment in December 2007 and an additional payment of $143 million in March 2008 of the Term B loan in connection with the mandatory offer under the Senior Credit Facility accompanied by a reduction on the variable interest rates on long-term debt. Interest capitalized on~~Repowering~~NRG projects under construction also contributed to this decrease. Offsetting these decreases was the $45 million payment made to CS for the benefit of CSF I in August 2008 to early settle the embedded derivative in the Company’s CSF I notes and preferred interests.

~~Income Tax Expense~~

NRG’s income tax expense increased by $231 million for the nine months ended September 30, 2008 compared to the same period in 2007. The effective tax rate was 40.1% and 39.0% for the nine months ended September 30, 2008 and 2007, respectively. The increase in income tax expense was primarily due to an increase in income.

(In millions except percentages)

Nine months ended September 30, 2008 2007

Income from continuing operations before income taxes $ 1,324 $ 769

Tax at 35% 463 269
State taxes, net of federal benefit 62 37
Foreign operations (10 ) (5 )
Valuation allowance (1 ) 1
Foreign dividends 5 21
Non-deductible interest 24 7
Change in German tax rate — (30 )
Section 199 Manufacturing Deduction (17 ) (3 )
Other permanent differences 5 3

Income tax expense $ 531 $ 300

Effective income tax rate 40.1 % 39.0 %

55

~~The increase in income tax expense was due to:~~


	•	~~Increase in income~~~~— pre-tax income increased by $555 million, with a corresponding increase of $220 million in income tax expense.~~

	•	~~Permanent differences~~~~— the Company’s effective tax rate differs from the US statutory rate of 35% due to:~~


	o	~~Lower tax rates in foreign jurisdictions~~~~— lower income tax rates at the Company’s foreign locations resulted in an income tax benefit in 2008 as compared to the same period in 2007 of $5 million.~~

	o	~~Taxable dividends from foreign subsidiaries~~~~— US taxability of foreign subsidiaries earnings resulted in an additional tax benefit of approximately $16 million in 2008 as compared to 2007.~~

	o	~~Non-deductible interest on CSFI CAGR Settlement~~— the Company executed the Note Purchase Amendment Agreement and Preferred Interest Amendment Agreement which allowed CSF I to early settle the CSFI CAGR. The result of this settlement resulted in an additional income tax expense of $16 million in 2008 as compared to the same period in 2007

	o	~~Change in German tax rate~~~~— due to a reduction in the German effective tax rate, income tax expense benefited by $30 million in 2007 as compared to the same period in 2008.~~

	o	~~Section 199 Manufacturing Deduction~~~~— as a result of the increase in pre-tax income during 2008, the Company recorded an additional income tax benefit of $14 million as compared to 2007.~~

The effective income tax rate may vary from period to period depending on, among other factors, the geographic and business mix of earnings and losses and changes in valuation allowances in accordance with SFAS 109. These factors and others, including the Company’s history of pre-tax earnings and losses, are taken into account in assessing the ability to realize deferred tax assets.

~~Income from Discontinued Operations, Net of Income Tax Expense~~

Discontinued operations included ITISA results for the nine months ended September 30, 2008 and the same period in 2007. NRG classifies as discontinued operations the income from operations and gains/losses recognized on the sale of projects that were sold or have met the required criteria for such classification pending final disposition. For the nine months ended September 30, 2008 and the same period in 2007, NRG recorded income from discontinued operations, net of income tax expense, of $172 million and $13 million, respectively. NRG closed the sale of ITISA during the second quarter 2008.

Results of Operations — Regional Discussions

The following is a detailed discussion of the results of operations of NRG’s major wholesale power generation business segments.

Texas

For a discussion of the business profile of the Company’s Texas operations, seepages ~~22-25~~23-26 of NRG Energy, Inc.’s ~~2007~~2008 Annual Report onForm 10-K.

Selected income statement data


	Three months ended September 30,								Nine months ended September 30,

(In millions except otherwise noted)	2008		2007			Change %			2008		2007			Change %
Three months ended March 31,																	2009		2008			Change %

Operating Revenues
Energy revenue	$	873	$	803			9	%	$	2,344	$	2,053			14	%	$	594	$	546			9	%
Capacity revenue		129		90			43			366		273			34			47		118			(60	)
Risk management activities		576		(4	)		N/A			53		2			N/A			263		(104	)		N/A
Contract amortization		69		59			17			215		167	��		29			15		63			(76	)
Other revenues		14		8			75			83		31			168			6		26			(77	)


Total operating revenues		1,661		956			74			3,061		2,526			21			925		649			43
Operating Costs and Expenses
Cost of energy		366		358			2			1,037		905			15
Cost of energy (including risk management activities)																		238		258			(8	)
Other operating expenses		154		175			(12	)		468		527			(11	)		168		164			2
Depreciation and amortization		108		113			(4	)		334		341			(2	)		117		113			4


Operating Income	$	1,033	$	310			233		$	1,222	$	753			62		$	402	$	114			253
MWh sold (in thousands)		13,111		13,792			(5	)		36,817		37,037			(1	)		10,239		11,031			(7	)
MWh generated (in thousands)		12,891		13,420			(4	)		36,147		36,157			—			10,073		10,756			(6	)
Business Metrics
Average on-peak market power prices ($/MWh)		102.82		62.44			65			112.80		63.60			77			33.66		71.30			(53	)
Cooling Degree Days, or CDDs (a)		1,417		1,458			(3	)%		2,509		2,380			5			126		74			70
CDD’s 30 year average		1,485		1,485			—			2,434		2,434			—
CDD’s 30 year rolling average																		94		95			(1	)
Heating Degree Days, or HDDs (a)		6		—			N/A			1,163		1,280			(9	)		903		1,053			(14	)
HDD’s 30 year average		5		5			—			1,221		1,208			1	%
HDD’s 30 year rolling average																		1,122		1,132			(1	)%


(a)		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.

~~Quarterly Results~~Operating Income

~~Operating Income~~

Operating income increased by ~~$723~~$288 million for the three months ended ~~September 30, 2008,~~March 31, 2009, compared to the same period in ~~2007,~~2008, primarily due to:

Risk management activities— an increase of ~~$580~~$367 million was primarily due to ~~$592~~$327 million in greater unrealized derivative gains ~~offset by $12~~and $40 million in ~~lower~~greater realized gains on settled financial transactions. These changes reflect a reduction in forward power and gas prices atduring the ~~end~~first quarter 2009 and the recognition of ~~the third quarter of 2008 compared~~previously deferred amounts due to the ~~end~~discontinuance of ~~the second quarter 2008. Gas and power prices in the comparable period of 2007 were relatively flat.~~certain 2009 cash flow hedges on baseload plant generation due to lower forecasted generation.

Energy revenues— increased by ~~$70~~$48 million due to higher ~~merchant~~average energy ~~revenue as a result of increased power~~ prices ~~and~~despite the lower sales ~~volumes offset by lower contract energy revenue.~~volume.

•

Cost of energy— decreased by $20 million reflecting lower coal and gas costs due to a decrease in coal and gas generation partially offset by higher unrealized derivative costs of energy.

Operating Revenues

Total operating revenues increased by ~~$705~~$276 million during the three months ended ~~September 30, 2008,~~March 31, 2009, compared to the same period in ~~2007,~~2008, due to:


	•		Risk management activities— gains of ~~$576~~$263 million were recognized for the three months ended ~~September 30, 2008~~March 31, 2009, compared to a $4$104 million loss in the same period in ~~2007.~~2008. The ~~$576~~$263 million ~~includes $573~~gains included $225 million of unrealized mark-to-market gains and $3$38 million in settled gains, or financial ~~revenue,~~income, compared to ~~$19~~$102 million in unrealized derivative losses and ~~$15~~$2 million of settled financial ~~gains~~losses in the same period in ~~2007.~~2008. The $573 million is the net effect of a $590 million gain from economic hedge positions and a $5 million loss on reversals of mark-to-market gains on economic hedges, partially offset by $12 million in unrealized mark-to-market losses on trading transactions. The $590$225 million gain from economic hedges ~~incorporates $261~~included a $110 million unrealized gain of previously deferred amounts in OCI due to discontinuance of certain 2009 trades resulting from lower than expected baseload plant generation and the remaining $115 million unrealized ~~gains~~gain was attributable to an increase in ~~the~~ value of forward sales ~~of electricity~~ and fuel ~~driven by~~due to lower power and ~~natural~~ gas prices. These hedges are considered effective economic hedges that do not receive cash flow hedge accounting treatment. The remaining $329 million in gains are from hedge ineffectiveness which was driven by decreasing gas prices while power prices decreased at a slower pace.

	•		Energy revenues— increased ~~by $70~~$48 million due to:

Energy ~~prices~~Prices – — increased by ~~$101~~$90 million ~~due to~~as the average realized merchant price was higher than the average contract price in both periods. Higher MWh sold under merchant market yielded a higher average energy ~~prices, reflecting a more favorable mix of~~price, even though the average realized merchant ~~versus contract sales, as well as a 30%~~price decreased by 11%. The 22% increase in ~~merchant prices offset by a 14% decrease in~~ contract price further contributed to the average energy ~~prices. The increase in merchant prices was driven by higher average natural gas prices in ERCOT as compared to 2007.~~price increase.

Generation—- decreased by ~~$31~~6% contributing to a $42 million ~~due to lower generation volumes. A 1% increase~~decrease in sales volume. This decrease was driven by a 7% or 524,000 MWh decrease in coal plant generation ~~was offset by~~and a ~~26%~~40% or 290,000 MWh decrease in gas plant ~~generation. Hurricane Ike~~generation, offset by a 102,000 MWh increase from the recently constructed Elbow Creek wind farm, which was not in ~~September 2008 caused major damage to the Houston area transmission grid which limited the Company’s ability to deliver power that normally would be generated to serve demand~~operation in the ~~region. The damage from hurricane Ike caused~~first quarter 2008. Coal plant generation was adversely affected by lower energy prices driven by a ~~lost opportunity~~51% decrease in average natural gas prices, increased production cost to generate with the start of NO_x rules contained in CAIR, and ~~deliver power reducing gas plant~~increased wind generation ~~for~~which shifted the ~~quarter.~~coal unit’s position in the bid stack. These factors led to increased hours where the coal units were either uneconomic to dispatch or where it was more economical to participate in the ancillary markets as compared to energy markets.

Capacity revenue— ~~increased~~decreased by ~~$39~~$71 million due to a ~~greater~~lower proportion of ~~base-load~~baseload contracts which contain a capacity component.

Contract amortization revenue— ~~increased~~resulting from the Texas Genco acquisition decreased by ~~$10~~$48 million due to the reduced volume of contracted energy ~~affected~~in 2009 as compared to 2008.

Other revenue— decreased by ~~a greater spread between contract~~$20 million due to lower ancillary services as well as reduced allocation of physical sales and ~~market prices used in the Texas Genco purchase accounting.~~emissions credits sales.

Cost of Energy

Cost of energy ~~increased~~decreased by $8$20 million during the three months ended ~~September 30, 2008,~~March 31, 2009, compared to the same period in ~~2007,~~2008, due to:

Natural gas costs— ~~increased~~decreased by ~~$22~~$48 million due to a ~~45% rise~~51% decline in average natural gas prices ~~offset by~~and a ~~26%~~40% decrease in gas-fired generation.

~~Coal costs~~Purchased energy— ~~increased~~decreased by $3$14 million due to ~~an increase~~a $33 per MWh decrease in ~~coal prices.~~average price to procure energy from the market combined with 174,000 fewer MWhs purchased.

Coal costs— decreased by $12 million as the prior period included a $15 million loss reserve related to a coal contract dispute, offset by a $3 million increase in the delivered cost of coal.

•

Ancillary Service Costs— ~~increased~~decreased by $11 million due to ~~an increase~~a decrease in purchased ancillary services costs incurred to meet contract ~~obligations and a rise in ancillary service costs charged by ERCOT.~~obligations.

~~These increases were partially offset by:~~


	•		Nuclear fuel expense— resulting from the Texas Genco purchase accounting, decreased ~~by $15~~$5 million as amortization of nuclear fuel inventory ~~established under Texas Genco purchase accounting~~ ended in ~~early~~March 2008.

These decreases were offset by:

	•		Derivative Cost of Energy— increased $56 million due to the recognition of unrealized losses on coal contracts of $38 million as the Company discontinued NPNS accounting for coal purchases combined with $16 million of unrealized losses associated with oil transactions hedging price risk on rail transportation contracts.

	•		~~Amortized contract costs~~Miscellaneous Cost of Energy— ~~decreased by $11~~increased $9 million ~~as amortization of water supply contracts established under Texas Genco purchase accounting ended in 2007.~~due to losses on settled financial transactions associated with oil transactions hedging price risk on rail transportation contracts.

Other Operating Expenses

Other operating expenses increased by $4 million during the three months ended March 31, 2009, compared to the same period in 2008, driven by an increase in general and administrative expense as a result of higher software implementation cost at STP, insurance premiums and corporate allocations.

5852

~~Other Operating Expenses~~

~~Other operating expenses decreased by $21 million during the three months ended September 30, 2008, compared to the same period in 2007, due to:~~


	•	~~Development costs~~ ~~— decreased by $35 million primarily due to the initial costs for developing the nuclear units 3 and 4 at STP associated with the~~~~Repowering~~~~NRG initiative that began in 2007. Development costs for STP nuclear units 3 and 4 are being capitalized in 2008.~~

~~This decrease was offset by:~~


	•	~~Operations & maintenance expense~~ — increased by $13 million which included increased maintenance activity at STP and increased diesel and chemical costs at the region’s fossil plants. The increase in maintenance activity at STP was the result of equipment and refueling outages.

~~Yearly Results~~Northeast Region

~~Operating Income~~

~~Operating income increased by $469 million for the nine months ended September 30, 2008, compared to the same period in 2007, primarily due to:~~


	•	~~Energy revenues~~ ~~— increased by $291 million due to higher merchant energy revenue as a result of higher power prices and sales volumes offset by lower contract energy revenue.~~

	•	~~Capacity revenue~~ ~~— increased by $93 million due to a greater proportion of base-load contracts which contain a capacity component.~~

	•	~~Risk management activities~~ — an increase of $51 million was primarily due to $128 million in greater unrealized derivative gains offset by $79 million in greater realized losses on settled financial transactions. These changes reflect a reduction in forward power and gas prices at the close of the nine months ended September 30, 2008. Gas and power prices in the comparable period 2007 were relatively flat.

~~These increases were offset by:~~


	•	~~Cost of energy~~ ~~— increased by $132 million reflecting the effects of increased natural gas and coal prices.~~

~~Operating Revenues~~

~~Total operating revenues increased by $535 million during the nine months ended September 30, 2008, compared to 2007, due to:~~


	•	~~Risk management activities~~ — gains of $53 million were recognized for the nine months ended September 30, 2008 compared to a $2 million gain in the same period in 2007. The $53 million includes $100 million of unrealized mark-to-market gains and $47 million in settled losses, or financial revenue, compared to $29 million in unrealized derivative losses and $31 million of settled financial gains in the same period in 2007. The $100 million is the net effect of a $95 million gain from economic hedge positions and a $20 million loss on reversals of mark-to-market gains on economic hedges, partially offset by $25 million in unrealized mark-to-market gains on trading transactions. The $95 million gain from economic hedges incorporates $123 million in unrealized gains in the value of forward sales of electricity and fuel driven by higher power and natural gas prices. These hedges are considered effective economic hedges that do not receive cash flow hedge accounting treatment. The remaining $28 million in losses are from hedge ineffectiveness which was driven by increasing gas prices while power prices rose at a slower pace.

	•	~~Energy revenues~~ ~~— increased by $291 million due to:~~


	o	~~Energy prices —~~~~increased by $292 million due to a more favorable mix of merchant versus contract sales resulting in a 38% increase in merchant prices offset by a 14% decrease in contract energy prices.~~


	o	~~Generation —~~remained largely unchanged at 36 million MWh. The mix of generation however did change with a 3% rise in nuclear generation at STP and a less than 1% rise in coal generation. This increase was offset by a 7% decrease in overall gas plant generation for the nine months ending September 2008. Hurricane Ike in September 2008 caused major damage to the Houston area transmission grid which limited the Company’s ability to deliver power that normally would be generated to serve demand in the region. The damage from hurricane Ike caused a lost opportunity to generate and deliver power reducing gas plant generation.


	•	~~Capacity revenue~~ ~~— increased by $93 million due to a greater proportion of base-load contracts which contain a capacity component.~~

	•	~~Other revenues —~~increased by $52 million related to a $22 million increase in ancillary services revenue in 2008, a $22 million increase of allocations for trading of emission allowances and carbon financial instruments, and increased activity in trading natural gas and coal of $8 million.

	•	~~Contract amortization revenue~~ ~~— increased by $48 million due to the volume of contracted energy affected by a greater spread between contract prices and market prices used in the Texas Genco purchase accounting.~~

~~Cost of Energy~~

~~Cost of energy increased by $132 million during the nine months ended September 30, 2008, compared to the same period in 2007, due to:~~


	•	~~Natural gas costs~~ ~~— increased by $136 million due to a 40% rise in average gas prices offset by a 7% decrease in gas-fired generation.~~

	•	~~Coal costs~~ ~~— increased by $16 million due to the settlement of a coal contract dispute and higher coal prices.~~

	•	~~Ancillary services~~ — increased by $19 million due to a $7 million increase in purchased ancillary services costs incurred to meet contract obligations and a $12 million rise in ancillary service costs incurred by ERCOT.

~~These increases were partially offset by:~~


	•	~~Amortized contract costs~~ ~~— decreased by $31 million as amortization of water supply contracts established under Texas Genco purchase accounting ended in 2007.~~

	•	~~Nuclear fuel expense~~ ~~— decreased by $11 million as amortization of nuclear fuel inventory established under Texas Genco purchase accounting ended in early 2008.~~

	•	~~Purchased power~~ ~~— decreased by $6 million due to lower outage rates at the region’s baseload plants.~~

~~Other Operating Expenses~~

~~Other operating expenses decreased by $59 million during the nine months ended September 30, 2008, compared to 2007, due to:~~


	•	~~Development costs~~ ~~— decreased by $81 million primarily due to the initial costs for developing the nuclear units 3 and 4 at STP associated with the~~~~Repowering~~~~NRG initiative that began in 2007. Development costs for STP nuclear units 3 and 4 are being capitalized in 2008.~~

~~This decrease was primarily offset by:~~


	•	~~Operations & maintenance expense~~ — increased by $20 million related to increased chemical and diesel costs at the region’s fossil plants, STP equipment retirements and refueling outage, and the timing of annual outages at the WA Parish and Limestone plants.

~~Northeast Region~~

For a discussion of the business profile of the Northeast region, seepages ~~25-28~~27-29 of NRG Energy, Inc.’s ~~2007~~2008 Annual Report onForm 10-K.

Selected income statement data


	Three months ended September 30,							Nine months ended September 30,

(In millions except otherwise noted)	2008		2007		Change %			2008		2007		Change %
Three months ended March 31,															2009		2008			Change %

Operating Revenues
Energy revenue	$	324	$	319		2	%	$	873	$	845		3	%	$	181	$	264			(31	)%
Capacity revenue		117		126		(7	)		328		302		9			96		110			(13	)
Risk management activities		223		28		N/A			39		23		70			182		(38	)		N/A
Other revenues		13		29		(55	)		62		69		(10	)		5		24			(79	)


Total operating revenues		677		502		35			1,302		1,239		5			464		360			29
Operating Costs and Expenses
Cost of energy		198		199		(1	)		557		506		10
Cost of energy (including risk management activities)																117		168			(30	)
Other operating expenses		89		92		(3	)		273		298		(8	)		94		93			1
Depreciation and amortization		26		25		4			77		74		4			29		26			12


Operating Income	$	364	$	186		96		$	395	$	361		9		$	224	$	73			207
MWh sold (in thousands)(b)		3,588		4,058		(12	)		10,424		10,754		(3	)
MWh sold (in thousands)																2,637		3,591			(27	)
MWh generated (in thousands)		3,588		4,058		(12	)		10,424		10,754		(3	)		2,637		3,591			(27	)
Business Metrics
Average on-peak market power prices ($/MWh)		108.44		78.28		39			100.66		75.89		33
Cooling Degree Days, or CDDs(a)		446		511		(13	)		611		672		(9	)
CDD’s 30 year average		430		430		—			534		534		—
Heating Degree Days, or HDDs(a)		135		122		11	%		3,866		4,116		(6	)%
HDD’s 30 year average		159		159		—			4,126		4,126		—
Average on-peak market power prices ($/MWh)_(b)																58.29		86.16			(32	)
Cooling Degree Days, or CDDs_(a)																—		—			—
CDD’s 30 year rolling average																—		—			—
Heating Degree Days, or HDDs_(a)																3,207		2,961			8
HDD’s 30 year rolling average																3,093		3,127			(1	)%


(a)		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.

(b)		MWh sold are shown net of MWh purchased to satisfy certain load contracts in the region.

~~Quarterly Results~~Operating Income

~~Operating Income~~

Operating income increased by ~~$178~~$151 million for the three months ended ~~September 30, 2008,~~March 31, 2009, compared to the same period in ~~2007~~2008 due to:

Operating revenues —increased by ~~$175~~$104 million due to favorable impact of risk management activities, offset by lower energy, capacity and other revenues.

Cost of energy –decreased by $51 million due to lower generation and fuel costs.

Operating Revenues

Operating revenues increased by ~~$175~~$104 million for the three months ended ~~September 30, 2008,~~March 31, 2009, compared to the same period in ~~2007,~~2008, due to:

Risk management activities— gains of ~~$223~~$182 million were recorded for the three months ending ~~September 30, 2008,~~March 31, 2009, compared to ~~gains~~losses of ~~$28~~$38 million during the same period in ~~2007.~~2008. The ~~$223~~$182 million gain ~~includes $201~~included $122 million of unrealized mark-to-market gains and ~~$22~~$60 million in gains on settled transactions, or financial ~~revenue,~~income, compared to ~~$15~~$48 million in unrealized mark-to-market ~~gains~~losses and ~~$13~~$10 million in financial ~~revenue gains~~income during the same period in ~~2007.~~2008. The ~~$201~~$122 million unrealized gain ~~is the net effect~~included $107 million unrealized gain recognition of previously deferred amounts in OCI as a ~~$201 million gain from economic hedge positions, the reversal~~result of ~~$2 million~~discontinuance of ~~mark-to-market gains~~certain 2009 cash flow hedges on economic hedges, the reversal of $6 million of mark-to-market gains on trading activity and $8 million in unrealized mark-to-market gains on trading activity. Gains are driven by decreases in power and gas prices.baseload plants generation due to lower forecasted generation.


	•		Energy revenues —~~increased~~decreased by $5$83 million due to:


	o		Energy prices— ~~increased~~decreased by ~~$49~~$32 million reflecting an average ~~19% rise~~12% decline in merchant energy ~~prices of $60 million.~~prices. This ~~increase~~decrease was partially offset by ~~lower~~higher net contract revenue of $11 million driven by ~~higher~~lower net costs ~~as a result of~~incurred in meeting obligations under load serving contracts in the PJM market.

	o		Generation— decreased by ~~$44~~$63 million due to a ~~net 12%~~27% decrease in generation in ~~2008~~2009 compared to ~~2007. The~~2008, driven by a 26% decrease ~~in generation represents a 4% decline~~ in coal generation and a ~~53%~~48% decrease in ~~oil-fired~~New York City gas generation. Coal generation ~~and 26% lower gas-fired generation~~in western New York declined 17% or 286,000 MWhs due to a ~~cooler summer~~20 day planned outage in ~~2008 compared~~January 2009 for the baghouse equipment tie in work on one of the region’s generators combined with a transmission line outage starting in mid-March which limited the flow of power out of western New York thus depressing energy prices and creating reserve shut down hours for the region’s coal units. Coal generation at the Indian River facility declined 36% or 417,000 MWhs. Weakened demand for power combined with low gas prices resulted in node prices at the Indian River facility being under $55 per MWh for 63% of the available hours during the first quarter 2009 versus only 24% in the first quarter 2008. Lower prices combined with higher cost of production from the introduction of RGGI and NO_x rules contained in CAIR resulted in increased hours where the units were uneconomic to ~~2007.~~dispatch. The Somerset facility experienced similar weakened demand and low gas prices, with generation down 62% or 123,000 MWh. The decline in gas generation is largely attributable to fewer run hours for voltage support at the Arthur Kill facility.

Capacity revenues— decreased by $9$14 million due to:

NYISO— capacity revenues decreased by $9$13 million due to unfavorable prices. The lower capacity market prices are a result of NYISO’s reductions in Installed Reserve Margins and ICAP in-city mitigation rules effective March 2008. ~~These decreases were offset by higher capacity cash flow hedge revenue.~~

PJM— capacity revenues decreased by $4$3 million due to lower capacity prices.

NEPOOL— capacity revenues increased by $2 million due to higher volume of Locational Forward Reserve Market, or LFRM, revenues on the Cos Cob repowered unit which entered service in June 2008.

Other revenues— decreased by $19 million due to $10 million lower allocations of net physical gas sales and $7 million due to decreased activity in the trading of emission allowances.

Natural gas costs— decreased by $33 million due to lower gas generation and 38% lower average prices per MMBtu.

Coal costs— decreased by $21 million, or 22%, due to 26% lower coal generation as discussed in energy revenues above.

Fuel risk management activities— increased by $8 million due to increased mark-to-market losses on fuel hedges.

Carbon emissions expense— increased by $5 million due to the January 1, 2009 implementation of RGGI and the recognition of carbon compliance cost under this program.

Oil costs— increased by $4 million due to higher ~~capacity prices.~~

~~Cost of Energy~~

~~Cost of energy decreased by $1 million for the three months ended September 30, 2008, compared to the same period in 2007, due to:~~

~~These decreases were offset by:~~

~~Other Operating Expenses~~

Other operating expenses decreased by $3 million for the three months ended September 30 2008, compared to the same period in 2007, due to a $3 million property tax credit received in 2008 at the Arthur Kill plant.

~~Yearly Results~~

~~Operating Income~~

~~Operating income increased by $34 million for the nine months ended September 30, 2008, compared to the same period in 2007 due to:~~


	•	~~Operating revenues —~~~~increased by $63 million due to higher energy revenue, capacity revenue and risk management revenues.~~

	•	~~Other operating expenses~~ ~~— decreased by $25 million consisting due to lower major maintenance expenses, property taxes and utilities.~~

~~These favorable variances were offset by:~~


	•	~~Cost of energy~~ — increased by $51 million due to higher coal costs, increased coal transportation surcharges and higher natural gas prices. These were offset by lower oil costs from lower oil-fired generation due to a warmer summer and colder winter in 2007 compared to 2008.

~~Operating Revenues~~

~~Operating revenues increased by $63 million for the nine months ended September 30, 2008, compared to the same period in 2007, due to:~~


	•	~~Energy revenues —~~~~increased by $28 million due to:~~


	o	~~Energy prices~~ — increased by $102 million reflecting an average 12% rise in merchant energy prices. This was offset by lower contract revenue of $45 million driven by higher net costs incurred to service PJM contracts as a result of the increase in market energy prices.

	o	~~Generation~~ — decreased by $29 million due to a net 3% decrease in generation. The decrease in generation represents a 52% decrease in oil-fired generation and a 14% decrease in gas-fired generation. These results are due to a warmer summer and colder winter in 2007. This decrease was offset by a 4% increase in coal generation as a result of the timing of outages at the Huntley and Indian River plants and higher reliability at the Huntley plant.


	•	~~Capacity revenues~~ ~~— increased by $26 million due to:~~


	o	~~PJM~~ ~~— capacity revenues increased by $21 million reflecting recognition of nine months of revenue from the RPM capacity market (effective on June 1, 2007) in 2008 compared to four months in 2007.~~

	o	~~NEPOOL~~ — capacity revenues increased $14 million consisting of $7 million from higher capacity prices and $7 million from increased revenue recognized on the Norwalk RMR contract (effective on June 19, 2007).

	o	~~NYISO~~ — capacity revenues decreased by $9 million due to unfavorable prices. The lower capacity market prices are a result of NYISO’s reductions in Installed Reserve Margins and ICAP in-city mitigation rules effective March 2008. These decreases were offset by higher capacity cash flow hedge revenue.


	•	~~Risk management activities~~ — gains of $39 million were recorded for the nine months ending September 30, 2008, compared to gains of $23 million during the same period in 2007. The $39 million gain includes $41 million of unrealized mark-to-market gains and $2 million of losses in settled transactions, or financial revenue, compared to $26 million in unrealized mark-to-market losses and $49 million in financial revenue gains during the same period in 2007. The $41 million unrealized gains is the net effect of a $58 million gain from economic hedge positions, the reversal of $11 million of mark-to-market gains on economic hedges, the reversal of $7 million of mark-to-market gains on trading activity and $1 million in unrealized mark-to-market gains on trading activity. Gains are driven by increases in power and gas prices.

~~These gains were offset by:~~


	•	~~Other revenues~~ ~~— decreased by $7 million due to $21 million lower net physical gas sales in 2008 offset by $15 million from 2008 sales of carbon financial instruments.~~

~~Cost of Energy~~

~~Cost of energy increased by $51 million for the nine months ended September 30, 2008, compared to the same period in 2007, due to:~~


	•	~~Coal costs~~ ~~— increased by $54 million due to 4% higher coal generation, higher coal costs and fuel transportation surcharges.~~

	•	~~Natural gas costs~~ ~~— increased by $20 million, despite 14% lower generation, due to higher natural gas prices.~~

~~These increases were offset by:~~


	•	~~Oil costs~~ ~~— decreased by $23 million due to lower~~ oil-fired generation as a result of a ~~warmer summer and~~ colder ~~winter in 2007.~~January 2009.

~~Other Operating Expenses~~

~~Other operating expenses decreased by $25 million for nine months ended September 30, 2008, compared to the same period in 2007, due to:~~

South Central Region

For a discussion of the business profile of the South Central region, seepages ~~28-30~~29-31 of NRG Energy, Inc.’s ~~2007~~2008 Annual Report onForm 10-K.

Selected income statement data


	Three months ended September 30,								Nine months ended September 30,

(In millions except otherwise noted)	2008			2007		Change %			2008		2007		Change %
Three months ended March 31,																2009			2008		Change %

Operating Revenues
Energy revenue	$	145		$	126		15	%	$	375	$	314		19	%	$	96		$	100		(4	)%
Capacity revenue		59			56		5			174		163		7			68			57		19
Risk management activities		23			11		109			13		19		(32	)		(7	)		13		(154	)
Contract amortization		7			7		—			18		18		—			6			6		—
Other revenues		(1	)		—		N/A			4		—		N/A			(1	)		3		(133	)


Total operating revenues		233			200		17			584		514		14			162			179		(9	)
Operating Costs and Expenses
Cost of energy		156			131		19			360		317		14
Cost of energy (including risk management activities)																	110			88		25
Other operating expenses		25			21		19			80		83		(4	)		22			22		—
Depreciation and amortization		16			17		(6	)		50		51		(2	)		17			17		—


Operating Income	$	36		$	31		16		$	94	$	63		49		$	13		$	52		(75	)
MWh sold (in thousands)		3,383			3,748		(10	)		9,448		9,579		(1	)		3,169			3,088		3
MWh generated (in thousands)		2,828			3,192		(11	)		8,469		8,416		1			2,706			3,024		(11	)
Business Metrics
Average on-peak market power prices ($/MWh)		84.88			60.42		40			79.14		60.80		30			37.30			67.73		(45	)
Cooling Degree Days, or CDDs(a)		1,027			1,249		(18	)		1,577		1,853		(15	)
CDD’s 30 year average		997			997		—			1,487		1,487		—
Heating Degree Days, or HDDs(a)		16			10		60	%		2,239		2,080		8
HDD’s 30 year average		33			33		—			2,246		2,226		1	%
Cooling Degree Days, or CDDs_(a)																	6			5		20
CDD’s 30 year rolling average																	31			31		—
Heating Degree Days, or HDDs_(a)																	1,805			1,885		(4	)
HDD’s 30 year rolling average																	1,895			1,914		(1	)%


(a)		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.

~~Quarterly Results~~

~~Operating Income~~

Operating income ~~increased~~decreased by $5$39 million for the three months ended ~~September 30, 2008,~~March 31, 2009, compared to the same period in ~~2007,~~2008, primarily due to:


	•		Operating revenues—~~increased~~ decreased by ~~$33~~$17 million due to ~~increases~~decreases in risk management activities, energy revenue, and other revenues. These decreases were offset by an increase in capacity ~~revenue and risk management activities.~~revenue. Mild weather ~~in the summer months reduced demand from the region’s cooperative customers, thereby allowing sales~~and lower merchant power prices contributed to the merchant market at higher prices. This increase was offset by the impacts of hurricane Gustav which caused major power outages in the region that limited demand from the cooperative customers during a period when the region would typically be purchasing power across the daily peaks. Hurricane Gustav also inflicted major damage to the transmission grid which limited the Company’s ability to deliver power and restricted the output of the Big Cajun II coal plant.decrease.

	•		Cost of ~~energy~~energy — increased by ~~$25~~$22 million due to higher purchased energy ~~and natural gas~~ costs ~~offset by lower coal generation costs.~~reflecting increased use of the region’s tolled facilities.

Operating Revenues

Operating revenues ~~increased~~decreased by ~~$33~~$17 million for the three months ended ~~September 30, 2008,~~March 31, 2009, compared to the same period in ~~2007,~~2008, due to:

Risk Management Activities— ~~gains~~losses of ~~$23~~$7 million were recognized during the ~~third~~first quarter ~~2008~~2009 compared to gains of ~~$11~~$13 million recognized during the same period in ~~2007.~~2008. The ~~$23~~$7 million ~~gain includes $27~~loss included $20 million in unrealized ~~gains~~losses offset by realized ~~losses~~gains of $4$13 million compared to ~~$10~~$9 million in unrealized gains and $1$4 million in realized gains for the same period in ~~2007.~~2008. The ~~$27~~$20 million unrealized ~~gain is~~loss was the net effect of a ~~$30~~$6 million unrealized mark-to-market gain from trading activity and the reversal of $3$26 million of mark-to-market ~~gains~~losses on trading activity. ~~Unrealized gains are primarily driven~~

	•		Energy revenues— decreased by ~~decreases~~$4 million due to a $15 million decline in ~~power~~contract revenue offset by an $11 million increase in merchant energy revenues. The decline in contract revenue reflected a $13 million drop due to the expiration of a contract with a regional utility and ~~gas~~a $2 million decrease in cost pass through from the cooperatives. The expiration of the contract freed up energy to be sold into the merchant market, but at lower average prices. Increased use of the region’s tolled facility provided additional energy to the merchant market.

	•		Capacity revenues—capacity revenue increased by $3$11 million due to ~~increased~~a $9 million increase from a new capacity agreement with a regional utility and a $3 million increase in capacity revenue from region’s Rockford plants which dispatch into the PJM market.

Cost of Energy

Cost of energy increased by ~~$25~~$22 million for the three months ended ~~September 30, 2008,~~March 31, 2009, compared to the same period in ~~2007,~~2008, due to:


	•		Purchased energy— increased by ~~$14~~$16 million reflecting higher ~~gas~~fuel costs associated with an increase of 532,000 MWhs sourced from the region’s tolled facility and higher capacity payments on the tolled facility. The region’s tolling ~~agreements and market purchases.~~agreement covered three months in 2009 compared to one month in 2008.

	•		~~Natural gas costs~~ Fuel risk management activities—increased by ~~$12~~$8 million ~~as a result of the Bayou Cove~~ and ~~Big Cajun I Peaker plants running extensively~~included $5 million in unrealized losses related to ~~support transmission system stability after hurricane Gustav.~~fuel transportation hedging activities and $3 million in realized losses associated with that same hedging activity.

~~These increases were offset by:~~

This increase was offset by decreases in coal costs of $1 million and natural gas costs of $1 million, respectively:


	•		Coal costs— decreased by $1 million due to ~~$6 million decline related to a 15%~~an 11% reduction in coal generation asand a ~~result of hurricane Gustav~~decrease in fuel transportation surcharges offset by a ~~$5 million rise~~contractual increase in ~~coal unit costs as a result of increases in fuel transportation surcharges.~~

rail contract base rates.

~~Other Operating Expenses~~

~~Other operating expenses increased by $4 million for the three months ended September 30, 2008, compared to the same period in 2007, due to:~~


•	~~G&A Expense~~ ~~— $2 million higher corporate allocations in 2008 compared to the same period in 2007.~~

•		~~Operating and maintenance expense~~Natural gas costs— ~~increase of~~decreased by $1 million ~~due to higher labor expenses and higher major maintenance expenses.~~as a result of falling gas prices offset by a 50% increase in generation from the region’s gas peaking plants.

6656

~~Yearly Results~~West Region

~~Operating Income~~

~~Operating income increased by $31 million for the nine months ended September 30, 2008, compared to the same period in 2007, due to:~~


	•	~~Operating revenues —~~~~increased by $70 million due to the increase in energy revenue and capacity revenue offset by an unfavorable impact of risk management activities.~~

	•	~~Cost of energy~~ ~~— increased by $43 million due to higher purchased energy, natural gas coal transportation costs, and transmission costs.~~

~~Operating Revenues~~

~~Operating revenues increased by $70 million for the nine months ended September 30, 2008, compared to the same period in 2007, due to:~~


	•	~~Energy revenues~~ — increased by $61 million due to $57 million in higher merchant energy revenues and $4 million of improved contract energy revenues. The growth in merchant energy revenues reflects a 1% rise in total MWh generated combined with a 6% decrease in contract load MWh thereby allowing for more sales to the merchant market at higher prices. The increase in revenue from contract load is driven by higher fuel cost pass-through adjustments for the region’s cooperative customers, while mild weather and the impacts of hurricane Gustav lowered load requirements. Megawatt hour sales to contract customers decreased 6% in 2008 as compared to 2007. Merchant energy MWh sold increased by 35%.

	•	~~Capacity revenues~~ — increased by $11 million due to new peak loads set by the region’s cooperative customers which resulted in $6 million of additional capacity payments and increased RPM capacity payments of $5 million from the PJM market.

~~These increases were offset by:~~


	•	~~Risk Management Activities~~ — gains of $13 million were recognized during the first nine months of 2008 compared to $19 million in gains recognized during the same period in 2007. Unrealized gains in 2008 of $17 million offset by realized losses of $4 million compared to $14 million of unrealized gains and $5 million of realized gains in 2007. The $17 million unrealized gain is the net effect of a $31 million unrealized mark-to-market gain from trading activities in the region offset by the reversal of $14 million of mark-to-market gains on trading activity. Unrealized gains are primarily driven by decreases in power and gas prices.

~~Cost of Energy~~

~~Cost of energy increased by $43 million for the nine months ended September 30, 2008, compared to the same period in 2007, due to:~~


	•	~~Purchased energy~~ — increased by $18 million reflecting a 28% increase in the average cost per MWh of purchased energy which reflects higher gas costs associated with the region’s tolling agreements. This increase was offset by a decrease in purchased MWh as increased plant availability reduced power purchases required to support contract load.

	•	~~Natural gas costs~~ ~~— increased $12 million. The region’s Bayou Cove and Big Cajun I Peaker plants ran extensively to support transmission system stability after hurricane Gustav in September 2008.~~

	•	~~Coal costs~~ — increased by $7 million due to a $2 per ton increase in fuel transportation surcharges. These increases were offset by a 1% drop in coal generation and a $3 million decrease in allocated rail car lease fees among the regions. This allocation of the railcar lease better reflects the actual usage of the Company’s railcar fleet.

	•	~~Transmission costs~~ ~~— increased by $6 million due to additional point-to-point transmission costs driven by an increase in merchant energy sales.~~

~~Other Operating Expenses~~

~~Other operating expenses decreased by $3 million for the nine months ended September 30, 2008, compared to the same period in 2007, due to:~~


	•	~~G&A Expense~~ — Franchise tax decreased by $7 million due to a retroactive charge recorded in the first quarter 2007. The Louisiana state franchise tax is assessed on the Company’s total debt and equity that significantly increased following the Acquisition of Texas Genco LLC. This decrease was offset by $5 million in higher corporate allocations in 2008 compared to the same period in 2007.

	•	~~Operating and maintenance expense~~ — Major maintenance decreased by $5 million due to more extensive spring outage work performed at the Big Cajun II plant in 2007 compared to the same period in 2008. Normal maintenance rose $2 million as a result of increased forced outages and higher contractor costs.

~~West Region~~

For a discussion of the business profile of the West region, seepages ~~30-32~~31-33 of NRG Energy, Inc.’s ~~2007~~2008 Annual Report onForm 10-K.

Selected income statement data


	Three months ended September 30,							Nine months ended September 30,

(In millions except otherwise noted)	2008		2007		Change %			2008		2007		Change %
Three months ended March 31,															2009			2008		Change %

Operating Revenues
Energy revenue	$	12	$	1		N/A		$	25	$	2		N/A		$	2		$	—		N/A
Capacity revenue		28		32		(13	)%		97		87		11	%		29			38		(24	)%
Risk management activities		—		—		—			—		—		—			(3	)		—		N/A
Other revenues		—		—		—			5		1		400			—			—		—


Total operating revenues		40		33		21			127		90		41			28			38		(26	)
Operating Costs and Expenses
Cost of energy		11		1		N/A			25		2		N/A
Cost of energy (including risk management activities)																4			2		100
Other operating expenses		14		19		(26	)		52		58		(10	)		25			18		39
Depreciation and amortization		2		1		100			6		2		200			2			1		100


Operating Income	$	13	$	12		8		$	44	$	28		57		$	(3	)	$	17		(118	)
MWh sold (in thousands)		124		4		N/A			213		5		N/A			169			150		13
MWh generated (in thousands)		124		4		N/A			213		5		N/A			169			150		13
Business Metrics
Average on-peak market power prices ($/MWh)		96.72		68.87		40			91.52		65.93		39			40.46			80.30		(50	)
Cooling Degree Days, or CDDs(a)		687		634		8			893		770		16
CDD’s 30 year average		506		506		—			663		663		—
Heating Degree Days, or HDDs(a)		61		91		(33	)%		2,157		1,917		13
HDD’s 30 year average		108		108		—			2,098		2,081		1	%
Cooling Degree Days, or CDDs_(a)																—			—		—
CDD’s 30 year rolling average																7			7		—
Heating Degree Days, or HDDs_(a)																1,410			1,525		(8	)
HDD’s 30 year rolling average																1,419			1,434		(1	)%


(a)		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.

~~Quarterly Results~~

Operating Income

Operating income ~~increased~~decreased by $1$20 million for the three months ended ~~September 30, 2008,~~March 31, 2009, compared to the same period in ~~2007,~~2008, due to:


	•	~~Energy revenues~~ ~~— increased by $11 million due to the dispatch of the El Segundo plant outside of the tolling agreement in 2008. In 2007, no such dispatch occurred.~~

	•	~~Other Operating Expenses~~Capacity revenues — — decreased by ~~$5 million due to a reduction in~~~~Repowering~~~~NRG permitting expenses for the El Segundo and Carlsbad Energy Centers for 2008 as compared to 2007.~~

~~These increases were partially offset by:~~


	•	~~Cost of energy —~~~~increased by $10 million due to the 2008 dispatch of the El Segundo plant.~~

	•	~~Capacity revenues~~ ~~— decreased by $4~~$9 million primarily due to expiration of a two year tolling agreement at the El Segundo facility ~~partially offset by the tolling agreement at the Long Beach plant:~~


	o	~~El Segundo~~ ~~— The expiration of the two year tolling agreement at the end of~~in April ~~resulted in a decrease of $5 million in capacity revenues for the three months ended September 30,~~ 2008.

	o	~~Long Beach~~ — On August 1, 2007, NRG successfully completed the repowering of a 260 MW natural gas-fueled generating plant at its Long Beach generating facility. The plant contributed $1 million in incremental capacity revenues for the three months ended September 30, 2008.

~~Yearly Results~~

~~Operating Income~~

~~Operating income increased by $16 million for the nine months ended September 30, 2008, compared to the same period in 2007, due to:~~


	•	~~Capacity revenues~~ ~~— increased by $10 million primarily due to the tolling agreement at the Long Beach plant partially offset by the expiration of a two year tolling agreement at the El Segundo facility:~~


	o	~~Long Beach~~ — On August 1, 2007, NRG successfully completed the repowering of a 260 MW natural gas-fueled generating plant at its Long Beach generating facility. The plant contributed $15 million in incremental capacity revenues for the nine months ended September 30, 2008.

	o	~~El Segundo~~ ~~— The expiration of the two year tolling agreement at the end of April resulted in a decrease of $5 million in capacity revenues for the nine months ended September 30, 2008~~


•	~~Energy revenues~~ ~~— increased by $23 million due to the 2008 dispatch of the El Segundo plant outside of the tolling agreement in 2008. In 2007, no such dispatch occurred.~~

•		~~Other revenues~~Cost of energy — — increased by $4$2 million due to ~~increased trading activity~~a write down to market of ~~emission allowances~~fuel oil inventory no longer used in ~~2008.~~the production of energy

•		Other operating ~~expense~~expenses— ~~decreased~~increased by $6$7 million due to ~~a reduction~~~~Repowering~~~~NRG permitting expenses~~higher major maintenance expense of $4$5 million ~~for~~associated with the El Segundo Unit 4 and ~~Carlsbad Energy Centers in 2008~~Encina facilities as ~~compared to 2007. In addition an environmental liability~~well as normal maintenance expense of $2 million ~~was recognized in 2007 related to the El Segundo plant.~~

~~These increases were partially offset by:~~


	•	~~Cost of energy —~~~~increased by $23 million due to the dispatch of the El Segundo plant outside of the tolling agreement in 2008. In 2007, no such dispatch occurred.~~

	•	~~Depreciation and amortization~~ ~~— increased by $4 million, reflecting the depreciation~~ associated with ~~the successful completion of the~~~~Repowering~~~~NRG project at the Long Beach plant.~~planned outages.

Liquidity and Capital Resources

Liquidity Position

As of ~~September 30, 2008~~March 31, 2009, and December 31, ~~2007,~~2008, NRG’s liquidity, excluding collateral received, was approximately ~~$3.0~~$3.1 billion and ~~$2.7~~$3.4 billion, respectively, ~~and~~ comprised of the following:


					March 31,			December 31,
(In millions)					2009			2008
As of	September 30, 2008		December 31, 2007

Cash and cash equivalents	$	1,483	$	1,132	$	1,188		$	1,494
Funds deposited by counterparties						1,275			754
Restricted cash		32		29		17			16


Total cash		1,515		1,161		2,480			2,264


Synthetic letter of credit availability		534		557
Revolver credit facility availability		1,000		997

Synthetic Letter of Credit Facility availability						884			860
Revolver Credit Facility availability						1,000			1,000

Total liquidity	$	3,049	$	2,715		4,364			4,124
Less: Funds deposited as collateral by hedge counterparties						(1,277	)		(760	)

Total liquidity, excluding collateral received					$	3,087		$	3,364

For the ~~nine~~three months ended ~~September 30, 2008,~~March 31, 2009, total liquidity increased by ~~$334~~$240 million due to ~~higher~~a rise in funds deposited by $521 million and increased availability of the synthetic letter of credit by $24 million, offset by lower cash balances ~~of $354~~by $306 million. Changes in cash balances are further discussed hereinafter underCash Flow Discussion. Cash and cash equivalents and funds deposited by counterparties at ~~September 30, 2008 are~~March 31, 2009, were predominantly held in money market funds invested in treasury securities, or treasury repurchase ~~agreements.~~agreements or government agency debt.

The line item “Funds deposited by counterparties” consist of cash collateral received from hedge counterparties in support of energy risk management activities, and it is the Company’s intention as of March 31, 2009 to limit the use of these funds. The change in these amounts was due to an increase of in-the-money positions as a result of decreasing forward prices. Depending on market fluctuation and the settlement of the underlying contracts, the Company will refund this collateral to the counterparties pursuant to the terms and conditions of the underlying trades. The Company’s balance sheet reflects a liability for cash collateral received within current liabilities.

Management believes that the Company’s liquidity position and cash flows from operations will be adequate to finance operating and maintenance capital expenditures, to fund dividends to NRG’s preferred shareholders, and other liquidity commitments. Management continues to regularly monitor the Company’s ability to finance the needs of its operating, financing and investing activity in a manner consistent with its intention to maintain a net debt to capital ratio in the range of45-60%.

SOURCES OF FUNDS

The principal sources of liquidity for NRG’s future operating and capital expenditures are expected to be derived from new and existing financing arrangements, asset sales, existing cash on hand and cash flows from operations.

Financing Arrangements

Senior Credit Facility

As of March 31, 2009, NRG has a Senior Credit Facility which is comprised of a senior first priority secured term loan, or the Term Loan Facility, a $1.0 billion senior first priority secured revolving credit facility, or the Revolving Credit Facility, and a $1.3 billion senior first priority secured synthetic letter of credit facility, or the Synthetic Letter of Credit Facility. The Senior Credit Facility was last amended on June 8, 2007. As of March 31, 2009, NRG had issued $416 million of letters of credit under the Synthetic Letter of Credit Facility, leaving $884 million available for future issuances. Under the Revolving Credit Facility, as of March 31, 2009, NRG had not issued any letters of credit.

TANE Facility

On February 24, 2009, NINA executed an Engineering, Procurement and Construction, or EPC, agreement with TANE, which specifies the terms under which STP Units 3 and 4 will be constructed. Concurrent with the execution of the EPC agreement, NINA and TANE entered into the TANE Facility wherein TANE, has committed up to $500 million to finance purchases of long-lead materials and equipment for the construction of STP 3 and 4. The TANE Facility matures on February 24, 2012, subject to two renewal periods, and provides for customary events of default, which include, among others: nonpayment of principal or interest; default under other indebtedness; the rendering of judgments; and certain events of bankruptcy or insolvency. Outstanding borrowings will accrue interest at LIBOR plus 3%, subject to a ratings grid, and are secured by substantially all of the assets of and membership interests in NINA and its subsidiaries. As of March 31, 2009, no amounts have been borrowed under the TANE Facility. NINA will be required to repay all outstanding amounts associated with its existing $20 million revolving credit facility before borrowing under the TANE Facility.

Dunkirk Power LLC Tax-Exempt Bonds

On April 15, 2009, NRG executed a $59 million tax-exempt bond financing through its wholly owned subsidiary, Dunkirk Power LLC. The bonds were issued by the County of Chautauqua Industrial Development Agency and will be applied towards construction of emission control equipment on the Dunkirk Generating Station in Dunkirk, NY. The bonds initially bear weekly interest based on the SIFMA rate, have a maturity date of April 1, 2042, and are enhanced by a letter of credit under the Company’s Revolving Credit Facility covering amounts drawn on the facility. The initial proceeds were $31 million with the remaining balance being released over time as construction costs are paid.

GenConn Energy LLC related financings

On April 27, 2009, a wholly owned subsidiary of NRG closed on an EBL in the amount of $121.5 million from a syndicate of banks. The purpose of the EBL is to fund the Company’s proportionate share of the project construction costs required to be contributed into GenConn, a 50% equity method investment of the Company. The EBL, which is fully collateralized with a letter of credit issued under the Company’s Synthetic Letter of Credit Facility, will bear interest at a rate of LIBOR plus 2% on drawn amounts. The EBL will mature on the earlier of the commercial operations date of the Middletown project or July 26, 2011. The EBL also features a mandatory prepayment of the portion of the loan utilized for the Devon project (approximately $56 million) becoming due on the earlier of Devon’s commercial operations date or January 27, 2011. The initial proceeds of the EBL were $61 million and the remaining amounts will be drawn as necessary to fund construction costs.

At the same time, GenConn secured financing from the same syndicate of banks for 50% of its project construction costs through a seven-year term loan facility, as well as a five year revolving working capital loan and letter of credit facility, collectively the GenConn Facility. The aggregate credit amount secured under the GenConn Facility, which is non-recourse to NRG, was $291 million, including $48 million for the revolving facility. No amounts were immediately drawn under the GenConn Facility.

First and Second Lien Structure

NRG has granted first and second liens to certain counterparties on substantially all of the Company’s ~~assets in the United States in order to secure primarily long-term obligations under power and gas sale agreements and related contracts.~~assets. NRG uses the first orand second lien structure to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or MWh equivalents. To the extent that the underlying hedge positions for a counterparty are in-the-money to NRG, the counterparty would have no claim under the lien program. The lien program ~~is limited by volumes~~limits the volume that can be hedged, not by the value of underlying out-of-the money positions. The first lien program does not require usNRG to post collateral above any threshold amount of exposure. Within the first and second lien structure, the Company can hedge up to 80% of its baseload capacity and 10% of its non-baseload assets with these counterparties for the first ~~rolling~~ 60 months ~~with such permitted hedging volumes~~and then declining thereafter. Net exposure to a counterparty on all trades must be positively correlated to the price of the relevant commodity for the first lien to be available to that counterparty. The first and second lien structure is not subject to unwind or termination upon a ratings downgrade of a ~~counterparty.~~counterparty or NRG and has no stated maturity date.

~~As part of the amendments to NRG’s Senior Credit Facility entered into on June 8, 2007, the Company obtained the ability to move its second lien counterparty exposure to the first lien on a~~~~pari passu~~~~basis with the Company’s existing first lien lenders. In exchange for moving to a~~~~pari passu~~ ~~basis with the Company’s first lien lenders, the counterparties agreed to relinquish letters of credit issued by NRG which they held as a part of their collateral package.~~

The Company’s lien counterparties may have a claim on ~~our~~the Company’s assets to the extent ~~their net positions areout-of-the-money.~~market prices exceed the hedged price. As of ~~September 30, 2008~~March 31, 2009, and ~~October~~April 23, ~~2008, the first lien~~2009, there was no exposure ~~of net~~to out-of-the-money positions to counterparties on hedges ~~was $405 million and $185 million, respectively. As of September 30, 2008 and October 23, 2008,~~under either the first or second ~~lien net out-of-the-money positions to counterparties on hedges was approximately $16 million and $2 million, respectively.~~liens.

7159

The following table summarizes the amount of MWs hedged against the Company’s baseload assets and as a percentage relative to the Company’s forecasted baseload capacity under the first and second lien structure as of ~~October~~April 23, ~~2008:~~2009:

Equivalent Net Sales secured by First and

Second Lien Structure (a) 2008(b) 2009 2010 2011 2012 2013

In MW 5,751 44,529 40,515 33,341 19,499 7,650
As a percentage of total forecasted baseload capacity (c) 56% 73% 68% 56% 33% 14%

Equivalent Net Sales Secured by First and Second Lien Structure (a) 2009 2010 2011 2012 2013

In MW (b)
4,969 4,612 3,704 2,123 788
As a percentage of total forecasted baseload capacity (c)
71 % 68 % 55 % 31 % 12 %

(a)
~~(a)~~ Equivalent Net Sales include natural gas swaps converted using a weighted average heat rate by region.

(b) ~~2008~~2009 MW value consists of ~~November~~May through December positions only.

(c) Forecasted baseload capacity under the first and second lien structure represents 80% of the total Company’s baseload assets.

~~Common Stock Finance I Debt~~Disposition of MIBRAG Investment

~~The Company’s Senior Credit Facility~~On February 25, 2009, NRG entered into an agreement to sell its 50% ownership interest in Mibrag B.V. to a consortium of Severočeské doly Chomutov, a member of the CEZ Group, and Senior Notes indentures contain restricted payment provisions limiting the use of funds for transactions such as common share repurchases. To maintain restricted payment capacity under the Senior Notes indentures, in March 2008J&T Group. Mibrag B.V.’s principal holding is MIBRAG which is jointly owned by the Company ~~executed an arrangement with CS to extend the notes~~ and preferred interest maturities of CSF I from October 2008 to June 2010. In addition, the settlement date of an embedded derivative, or CSFI CAGR, which is based on NRG’s share price appreciation beyond a 20% compound annual growth rate since the original date of purchase by CSF I, was extended 30 days to early December 2008.URS Corporation. As part of ~~this extension arrangement,~~ the ~~Company contributed 795,503 treasury shares~~transaction, URS Corporation also has entered into an agreement to ~~CSF I as additional collateral~~sell its 50% stake in MIBRAG. For its share, NRG expects to ~~maintain a blended interest rate in~~receive EUR202 million, subject to certain adjustments including transaction costs. The transaction is subject to customary closing conditions, including European Commission regulatory approvals and the ~~CSF I facility~~absence of ~~approximately 7.5%. Accordingly,~~material adverse changes. The sale is expected to close during the amount due at maturity in June 2010 for the CSF I notes and preferred interests will be $248 million. In August 2008, the Company amended the CSF I notes and preferred interests to early settle the CSFI CAGR. Accordingly, NRG made a cash paymentsecond quarter of ~~$45 million to CS for the benefit of CSF I, which was recorded to interest expense in the Company’s Consolidated Statement of Operations.~~2009.

On April 28, 2008, NRG completed the sale of its 100% interest in Tosli Acquisition B.V., or Tosli, which held all NRG’s interest in ITISA, to Brookfield Renewable Power Inc. (previously Brookfield Power Inc.), a wholly-owned subsidiary of Brookfield Asset Management Inc. In addition, the purchase price adjustment contingency under the sale agreement was resolved on August 7, 2008. In connection with the transaction, NRG entered into a foreign currency forward contract on March 12, 2009 to hedge the impact of exchange rate fluctuations on the sale proceeds. The foreign currency forward contract has a fixed exchange rate of 1.277. The contract requires NRG ~~received $300 million of cash proceeds from Brookfield, and removed $163 million of assets, including $59 million of cash, $122 million of liabilities, including $63 million of debt, and $15~~to pay EUR 200 million in ~~foreign currency translation adjustment from its 2008 condensed consolidated balance sheet As discussed in Note 3,~~~~Discontinued Operations~~~~, the activities of Tosli and ITISA have been classified as discontinued operations.~~exchange for $255 million on June 30, 2009.

The Company’s requirements for liquidity and capital resources, other than for operating its facilities, can generally be categorized by the following: (i) commercial operations activities; (ii) debt service obligations; (iii) capital expenditures includingRepoweringNRG and environmental; and (iv) corporate financial transactions including return of capital to shareholders.

Commercial Operations

NRG’s commercial operations activities require a significant amount of liquidity and capital resources. These liquidity requirements are primarily driven by: (i) margin and collateral posted with counterparties; (ii) initial collateral required to establish trading relationships; (iii) timing of disbursements and receipts (i.e., buying fuel before receiving energy revenues); and (iv) initial collateral for large structured transactions. As of ~~September 30, 2008,~~March 31, 2009, commercial operations had total cash collateral outstanding of ~~$390~~$176 million, and ~~$464~~$416 million outstanding in letters of credit to third parties primarily to support its economic hedging activities. As of March 31, 2009, total collateral held from counterparties was $1.3 billion and $34 million of letters of credit.

Future liquidity requirements may change based on the Company’s hedging activities and structures, fuel purchases, and future market conditions, including forward prices for energy and fuel and market volatility. In addition, liquidity requirements are dependent on NRG’s credit ratings and general perception of its creditworthiness.

Debt Service Obligations

~~Beginning in 2008,~~ NRG must annually offer a portion of its excess cash flow (as defined in the Senior Credit Facility) to its first lien lenders under the Term ~~B loan.~~Loan Facility. The percentage of excess cash flow offered to these lenders is dependent upon the Company’s consolidated leverage ratio (as defined in the Senior Credit Facility) at the end of the preceding year. Of the amount offered, the first lien lenders must accept 50% while the remaining 50% may either be accepted or rejected at the lenders’ option. ~~The mandatory annual offer required for 2008 was $446 million, against which the Company~~In March 2009, NRG made ~~a $300 million prepayment in December 2007. Of the remaining $146 million,~~and the lenders accepted a repayment of ~~$143~~approximately $197 million for the mandatory annual offer relating to 2008.

As of March 31, 2009, NRG had approximately $4.7 billion in ~~March 2008. The~~aggregate principal amount ~~retained by~~of unsecured high yield notes or Senior Notes, had approximately $2.4 billion in principal amount outstanding under the ~~Company can be used for investments, capital expenditures~~Term Loan Facility, and ~~other items as defined by~~had issued $416 million of letters of credit under the ~~Senior~~Company’s $1.3 billion Synthetic Letter of Credit Facility. The Revolving Credit Facility matures on February 2, 2011 and the Synthetic Letter of Credit Facility matures on February 1, 2013.

Capital Expenditures ~~and RepoweringNRG Equity Investments in Affiliates~~

For the ~~nine~~three months ended ~~September 30, 2008,~~March 31, 2009, the Company’s capital expenditures, including accruals, were approximately ~~$709~~$186 million, of which ~~$466~~$78 million was related toRepoweringNRG projects. The following table summarizes the Company’s capital expenditures for the ~~nine~~three months ended ~~September 30, 2008~~March 31, 2009, and the estimated capital expenditure and repowering investments forecast for the remainder of ~~2008.~~2009.

(In millions) Maintenance Environmental Repowering Total

Northeast $   8 $   39 $   — $   47
Texas 59 12 71
South Central (1 ) — (1 )
West 1 — 1 2
Wind development — — 28 28
Nuclear development — — 37 37
Other 2 — — 2

Total $   69 $   39 $   78 $   186

Estimated capital expenditures for the remainder of 2009 $   193 $   191 $   278 $   662

(In millions) Maintenance Environmental RepoweringNRG Total

Northeast $ 15 $ 93 $ 19 $ 127
Texas 94 17 82 193
South Central 7 5 — 12
West 2 — 28 30
NINA — — 55 55
Wind — — 282 282
Other 10 — — 10

Capital expenditures through September 30, 2008 128 115 466 709
Capital expenditures through the remainder of 2008 80 87 97 264

Total estimated capital expenditures for 2008 $   208 $   202 $   563 $      973

Total estimated repowering equity investments for 2008 N/A N/A $ 87 $ 87

RepoweringNRGcapital expenditures and investments—RepoweringNRG project capital expenditures consisted of approximately ~~$170~~$28 million ~~for wind turbines and construction~~ related ~~costs for~~to the ~~Elbow Creek~~Company’s Langford wind farm project which is currently under ~~construction and $112 million in turbine purchases for other wind projects currently under development.~~construction. In addition, the Company’sRepoweringNRG capital expenditures included ~~$82~~$12 million ~~related to~~for the construction of Cedar Bayou Unit 4 in Texas ~~$55~~and $37 million ~~related to~~for the development of STP Units 3 and 4 in ~~Texas, $28 million for the repowering of the El Segundo generating station in California, and $19 million for the construction of Cos Cob in Connecticut.~~Texas.

The Company’s estimated repowering capital expenditures for the remainder of ~~2008~~2009 are expected to ~~consist of~~be approximately ~~$57~~$278 million. Of this amount, $157 million ~~related~~is estimated for STP units 3 and 4 without giving effect to the construction and equipment procurement for the Elbow Creek wind farm project and other wind projects under development. In addition, the Company expects to incur additional 2008 capital expenditures of approximatelyany partner contributions or potential equity sell down, $13 million ~~towards~~is anticipated for the construction of Cedar Bayou Unit 4, and ~~$19 million towards~~ the ~~development~~balance is anticipated for the construction of ~~STP Units 3 and 4.~~the Langford wind farm.

~~Related to~~~~Repowering~~NRG, the Company expects to contribute equity of approximately $87 million to its Sherbino wind farm project in 2008 and has posted a letter of credit in that amount. For the nine months ended September 30, 2008, the Company invested $17 million in Sherbino.
Major maintenance and environmental capital expenditures— The Company’s baghouse ~~project~~projects at ~~its Huntley and Dunkirk plants~~western New York facilities resulted in environmental capital expenditures of ~~$70~~$39 million for the ~~nine~~three months ended ~~September 30, 2008.~~March 31, 2009. Other capital expenditures included ~~$31~~$25 million for STP fuel and ~~$63~~$34 million in maintenance capital expenditures in Texas primarily related to the W.A. Parish and Limestone plants.

NRG anticipates funding ~~these~~its maintenance capital projects primarily with funds generated from operating activities. ~~The~~In addition, on April 16, 2009, the Company ~~is also pursuing funding for certain~~closed on an approximately $59 million tax-exempt bond financing through its Dunkirk Power LLC subsidiary, with the bonds issued by the County of Chautauqua Industrial Development Agency. These funds are expected to fund environmental capital expenditures at the Dunkirk Generating facility in ~~the Northeast region through Solid Waste Disposal Bonds utilizing tax exempt financing, and expects to draw upon such funds during~~ 2009.

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Loans to affiliates— ~~During the first nine months~~As of ~~2008,~~March 31, 2009, the Company ~~loaned $15~~had funded approximately $44 million in ~~funds~~loans to GenConn Energy LLC, ~~or GenConn,~~ a 50/50/50 joint venture vehicle of NRG and ~~The~~the United Illuminating Company ~~as a part of the Devon plant project. On October 16, 2008, the Company loaned a further $15 million in funds to GenConn~~ as a part of the Devon and Middletown plant projects. These loans, which are in the form of an interest bearing note, mature in 2009, ~~at which point GenConn’s~~and will be fully repaid with the proceeds from the financing of GenConn. All future construction costs ~~are expected to~~for GenConn Energy LLC will be funded ~~through~~from the equity bridge loans of NRG and ~~The~~the United Illuminating Company and non-recourse project level financing.

Environmental Capital Expenditures

Based on current rules, technology and plans, NRG has estimated that environmental capital expenditures to be incurred ~~from 2008~~during the remainder of 2009 through 2013 to meet NRG’s environmental commitments will be approximately ~~$1.3~~$1.1 billion. These capital expenditures, in general, are related to installation of particulate, SO₂, NO_x, and mercury controls to comply with federal and state air quality rules and consent orders, as well as installation of “Best Technology Available” under the Phase II 316(b) ~~rule.~~Rule. NRG continues to explore cost effective alternatives that can achieve desired results. This estimate reflects anticipated schedules and controls related to CAIR, MACT for mercury, and the Phase II 316(b) rule which are under remand to the USEPA and, as such, the full impact on the scope and timing of environmental retrofits from any new or revised regulations cannot be determined at this time.

Capital Allocation

~~The following table summarizes~~In addition to the ~~major~~aforementioned planned investments in maintenance and environmental capital expenditures ~~for~~andRepoweringNRG in 2009, and the ~~referenced periods by region:~~

(In millions) Texas Northeast South Central Total

2008 $ 24 $ 172 $ 6 $ 202
2009 — 256 — 256
2010 7 187 52 246
2011 17 154 102 273
2012 27 67 100 194
2013 32 — 67 99

Total $ 107 $ 836 $ 327 $ 1,270

2009 repayment of Term Loan Facility debt to the first lien lenders, the Company’s Capital Allocation Plan includes the completion of the 2008 Capital Allocation Plan
~~In December 2007, the Company initiated its 2008 Capital Allocation Program,~~ with the ~~repurchase~~planned purchase of ~~2,037,700 shares~~$30 million of ~~NRG~~ common stock ~~during that month for approximately $85 million. In February 2008,~~as well as the ~~Company’s Board~~purchase of Directors authorized an additional $200 million in common share repurchases that would raise the total 2008 Capital Allocation Program to approximately $300 million. In the first quarter 2008, the Company repurchased 1,281,600 shares of NRG common stock for approximately $55 million. In the third quarter 2008, the Company repurchased an additional 3,410,283 of NRG common stock in the open market for approximately $130 million. As of September 30, 2008, NRG had repurchased a total of 6,729,583 shares of NRG common stock at a cost of approximately $270 million as part of its 2008 Capital Allocation Program.
~~2009 Capital Allocation Plan~~
~~On October 30, 2008, the Company announced its 2009 Capital Allocation Plan to purchase~~ an additional $300 million in common ~~stock. As part~~stock under the previously announced 2009 Capital Allocation Plan, with such purchases to be made from time to time at subject to market conditions and other factors, including as permitted by US securities laws.
Preferred Stock Dividend Payments
     For the three months ended March 31, 2009, NRG paid approximately $6 million, $4 million, and $4 million in dividend payments to holders of the Company’s 5.75%, 4%, and 3.625% Preferred Stock. On March 16, 2009, ~~plan,~~the outstanding shares of the 5.75% Preferred Stock converted into common stock and, as a result, there will be no further dividends paid with respect to this series of preferred stock.
CSF Share Lending Arrangement
     On February 20, 2009, CSF I and CSF II, wholly-owned unrestricted subsidiaries of the Company, ~~will invest over $511 million~~entered into Share Lending Agreements with affiliates of Credit Suisse Group, or CS, relating to the shares of NRG common stock currently held by CSF I and II in ~~maintenance~~connection with the CSF I and ~~environmental capital expenditures~~CSF II issued notes and preferred interests agreements, or CSF Debt, originally entered into on August 4, 2006, by and between CSF I and II and affiliates of CS. The Company entered into Share Lending Agreements due to the current lack of liquidity in the ~~existing assets~~stock borrow market for NRG shares and in order to maintain the intended economic benefits of the CSF Debt agreements. As of March 31, 2009 CSF I and ~~$118 million in projects under~~~~Repowering~~II have lent affiliates of CS 12,000,000 shares of the 21,970,903 shares of NRG ~~that are currently under construction or for which there exist current obligations. Finally, in addition~~common stock held by CSF I and II. The Share Lending Agreements permit affiliates of CS to ~~a scheduled debt amortization payment, in~~borrow up to the ~~first quarter 2009 the Company will offer its first lien lenders 50%~~total number of ~~its 2008 excess cash flow (as defined in the Senior Credit Facility).~~
shares of NRG common stock held by CSF I and II.
Benefit Plans Obligations

~~Based on the Company’s December~~As of March 31, ~~2007 measurement of its benefit obligation for~~2009, NRG contributed $6 million towards its three defined benefit pension plans to meet the ~~Company is~~Company’s 2009 benefit obligation. The Company’s expected contribution to ~~contribute $13 million to these plans from October 1, 2008 through March 31, 2009. Based on weak market performance of plan assets,~~ the plans ~~would require an additional~~is $24 million during the remainder of 2009. The total 2009 planned contribution of ~~approximately $60~~$30 million is a decrease of $30 million from the expected contributions as disclosed in Part II, Item 7 —Management’s Discussion and Analysis of Financial Condition and Results of Operations, Liquidity and Capital Resources, in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008. This decrease in the 2009 expected contributions is due to the adoption by the Company in ~~2009.~~March 2009 of the new funding method options now available. The new methods were made allowable under new IRS guidance on the application of recent Congressional legislation on funding requirements.

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Cash Flow Discussion

The following table reflects the changes in cash flows for the comparative ~~periods. All~~years; all cash flow categories include the cash flows from both continuing operations and discontinued operations:

(In millions)

Nine months ended September 30, 2008 2007

Net cash provided by operating activities $ 1,041 $ 976
Net cash used by investing activities $ (332 ) $ (232 )
Net cash used by financing activities $ (401 ) $ (375 )

(In millions)
Three months ended March 31, 2009 2008 Change

Net cash provided by operating activities $ 139 $ 60 $ 79
Net cash used by investing activities (259 ) (132 ) (127 )
Net cash used by financing activities (184 ) (224 ) 40

Net Cash Provided By Operating Activities

For the ~~nine~~three months ended ~~September 30, 2008,~~March 31, 2009, net cash provided by operating activities increased by ~~$65~~$79 million compared to the same period in ~~2007.~~2008. The difference was due to:
•
~~Increase~~Collateral paid and option premiums collected —In 2009, the changes in ~~generation~~collateral deposits paid and ~~energy prices— An increase in power generation and higher energy prices contributed to $278 million more in~~option premiums collected increased cash from operations ~~after adjusting net income for the effect~~by $177 million due to close out of ~~non-cash items for the first nine months of 2008 compared to 2007.~~commercial trade positions and lower commodity prices.

•
~~Collateral deposits~~Working capital —~~— During~~In 2009, the ~~first nine months~~cash used by working capital items increased by $69 million, primarily as a result of ~~2008, an increase~~higher inventory of $29 million and the balance due to other various changes in ~~net collateral deposits of $320 million to support the Company’s hedging~~assets and ~~trading activities reduced cash from operations by $213 million compared to the same period in 2007.~~liabilities.

Net Cash Used By Investing Activities

For the ~~nine~~three months ended ~~September 30, 2008,~~March 31, 2009, net cash used in investing activities was approximately ~~$100~~$127 million more than the same period in ~~2007.~~2008. This was due to:


•		Capital expenditures —— NRG’s capital expenditures increased by ~~$340~~$69 million due to~~RepoweringNRG~~ increased environmental capital expenditures which consists primarily of the Company’s baghouse projects ~~primarily related to $282 million for wind turbines related to Elbow Creek and other wind projects currently under development.~~in the Northeast.

•		~~Sale~~Trading of ~~discontinued operations~~emission allowances —Net ~~proceeds from the sale~~purchases and sales of ~~ITISA were $241~~emission allowances resulted in a decrease in cash of $57 million infor 2009 as compared to 2008.

•		Asset sales —— The Company received ~~$14~~$4 million in proceeds primarily from the sale of various assets in 2009 compared to proceeds of $12 million in proceeds primarily from the sale of rail cars in the ~~first nine months of 2008 compared to proceeds of $57 million for the sale of Red Bluff and Chowchilla II power plants and equipment in the~~ same period in ~~2007~~2008 for a net decrease in cash of ~~$43~~$8 million.

•	~~Trading of emission allowances~~~~— Net purchases and sales of emission allowances resulted in an increase in cash of $51 million for the first nine months of 2008 compared to 2007.~~

•	~~Equity Contribution —~~~~The Company contributed approximately $17 million to its equity investment in Sherbino.~~

Net Cash Used By Financing Activities

For the ~~nine~~three months ended ~~September 30, 2008,~~March 31, 2009, net cash used by financing activities ~~increased~~decreased by approximately ~~$26~~$40 million compared to ~~2007,~~2008, due to:


	•		Term ~~B loan~~Loan Facility debt payment —In ~~2008,~~2009, the Company paid down ~~$166~~$205 million of its Term ~~B loan,~~Loan Facility, including the payment of excess cash flow, as discussed above underDebt Service Obligations. The Company paid down ~~$25~~$151 million of its Term ~~B loan~~Loan Facility during ~~the first nine months of 2007~~2008 for a net cash decrease of ~~$141~~$54 million for the ~~nine months~~year ended ~~of 2008~~2009 compared to the same period in ~~2007.~~2008.

	•		Share repurchase —During 2009, the Company did not repurchase any common stock during the first ~~nine months of 2008, the Company repurchased approximately $185 million shares of NRG common stock,~~quarter in 2009, compared to ~~$268~~$55 million for ~~2007 for a net $83 million increase to cash for the nine months 2008 compared to the same period in 2007.~~

2008.


•	~~Sale of minority interest —~~~~The Company received $50 million in proceeds from the sale of minority interest in NINA in the first half of 2008.~~

•		Receipt from/(Payment ofof) financing element of acquired derivatives —For ~~the nine months of 2008,~~2009, the Company ~~paid~~received approximately ~~$49~~$40 million ~~related to~~for the settlement of gas swaps related to the acquisition of Texas Genco in ~~2006.~~

•	~~Issuance~~2006 compared to a payment of ~~debt —~~~~During the first nine months~~approximately $1 million for 2008 for a net increase in cash of ~~2008, the Company received $20 million in proceeds from the borrowings made by its subsidiaries.~~

•	~~Exercise of stock options —~~~~The Company received proceeds of $8 million from the exercise of stock options for the nine months ended 2008.~~$41 million.

NOL’s, Deferred Tax Assets and FIN 48 Implications

As of ~~September 30, 2008,~~March 31, 2009, the Company had generated a total domestic ~~continuing~~ pre-tax book income of ~~$1,249~~$481 million and foreign continuing pre-tax book income of ~~$75~~$15 million. In addition, NRG has cumulative foreign NOL carryforwards of ~~$253~~$235 million, of which ~~$54~~$47 million will expire starting in 2011 through ~~2017~~2018 and ~~$199~~of which $188 million ~~that~~ do not have an expiration date.

In addition to these amounts, the Company has ~~$709~~$556 million of tax effected unrecognized tax benefits which relate primarily to net operating losses for tax return purposes but have been classified as capital loss carryforwards for financial statements purposes and for which a full valuation allowance has been established. As a result of the Company’s tax position, and based on current forecasts, ~~we anticipate~~the Company anticipates income tax payments of up to $100 million ~~in 2008. Beginning in 2009, income tax payments will be approximately 30% of pre-tax book income.~~during 2009.

However, as the position remains uncertain, of the ~~$709~~$556 million of tax effected unrecognized tax benefits, the Company has recorded a non-current tax liability of ~~$138~~$272 million and may accrue the remaining balance as an increase to non-current liabilities until final resolution with the related taxing authority. The ~~$138~~$272 million non-current tax liability for unrecognized tax benefits is due to taxable earnings for ~~the period for~~ which there are no NOLs available to offset for financial statement purposes.

The Company ~~has been contacted for~~continues to be under examination by the Internal Revenue ~~Service for years 2004 through 2006. The audit commenced during the third quarter 2008 and is expected to continue for approximately 18 to 24 months.~~Service.

New and On-going Company Initiatives

Reliant Retail Acquisition

NRG also has arranged with Merrill Lynch, the current credit provider of Reliant, to provide continuing credit support to the retail business subsequent to closing. The Company negotiated a transitional credit sleeve facility, or CSRA, with Merrill Lynch under which NRG will contribute $200 million of cash into the retail entity. In conjunction with the CSRA, NRG, Reliant Retail, Merrill Lynch and certain counterparties will enter into offsetting trades to move collateral with respect to NRG’s in-the-money position in order to reduce Merrill Lynch’s actual and contingent collateral on Reliant Retail’s out-of-money position. The CSRA will provide collateral support for the retail enterprise up to November 1, 2010, while a transition to NRG supplying the retail business’ power requirements occurs, with limited ongoing collateral requirements. NRG will also have two potential cash contribution obligations: (i) in October 2009 of $250 million if a threshold level to be determined at closing is exceeded, and (ii) in October 2010 for up to $400 million at the sleeve unwind. The monthly fees for this sleeve facility is 5.875% on an annualized basis of the predetermined exposure as defined in the CSRA.

Disposition of MIBRAG Investment

On February 25, 2009, NRG entered into an agreement to sell its 50% ownership interest in Mibrag B.V. to a consortium of Severočeské doly Chomutov, a member of the CEZ Group, and J&T Group. Mibrag B.V.’s principal holding is MIBRAG, which is jointly owned by NRG and URS Corporation. As part of the transaction, URS Corporation also has entered into an agreement to sell its 50% stake in MIBRAG.

For its share, NRG expects to receive EUR 202 million, subject to certain adjustments including transaction costs. The transaction is subject to customary closing conditions, including European Commission regulatory approvals and the absence of material adverse changes. NRG expects to recognize a pre-tax gain of approximately $100 million to $120 million and to close on the sale during the second quarter of 2009. Prior to completion of the sale, NRG continues to record its share of MIBRAG’s operations to “Equity in earnings of unconsolidated affiliates.”

In connection with the transaction, NRG entered into a foreign currency forward contract on March 12, 2009, to hedge the impact of exchange rate fluctuations on the sale proceeds. The foreign currency forward contract has a fixed exchange rate of 1.277. The contract requires NRG to pay EUR 200 million in exchange for $255 million on June 30, 2009. For the three months ended March 31, 2009, NRG recorded an unrealized exchange loss of $9 million on the contract within “Other income/(expense), net.”

NRG will provide certain indemnities in connection with its share of the transaction. See Note 17,Guarantees,to this Form 10-Q for further discussion.

FORNRG Update

Beginning in January 2009, the Company transitioned toFORNRG 2.0 to target an incremental 100 basis point improvement to the Company’s ROIC by 2012. The initial targets forFORNRG 2.0 were based upon improvements in the Company’s ROIC as measured by increased cash flow. The economic goals ofFORNRG 2.0 will focus on: (i) revenue enhancement, (ii) cost savings, and (iii) asset optimization, including reducing excess working capital and other assets. TheFORNRG 2.0 program will measure its progress towards theFORNRG 2.0 goals by using the Company’s 2008 financial results as a baseline, while plant performance calculations will be based upon the appropriate historic baselines.

Nuclear Innovation North America

~~In March 2008, NRG formed Nuclear Innovation North America LLC, or~~ NINA is an NRG subsidiary focused on marketing, siting, developing, financing and investing in new advanced design nuclear projects in select markets across North America, including the planned STP units 3 and 4 that NRG is developing on a 50/50 basis with City of San Antonio’s agent City Public Service Board of San Antonio, or CPS Energy, at the STP nuclear power station site. ~~NRG’s rights to develop~~TANE, a wholly owned subsidiary of Toshiba Corporation, owns a non-controlling interest in NINA.

The STP ~~units 3 and 4 have been contributed to special purpose subsidiaries of NINA. NINA will focus only on the development of new projects and will not be involved~~Expansion received a favorable preliminary ranking in the ~~operations~~Department of Energy, or DOE, Loan Guarantee program and NINA submitted its part II application in mid-October. NRG believes DOE loan guarantee support is critical to new nuclear development projects. NINA is also actively pursuing additional loan guarantee options through the ~~existing STP units 1~~Japanese government and 2.due diligence by Japanese financing agencies is in progress.

On February 24, 2009, NINA executed an EPC agreement with TANE to build the STP expansion. The EPC agreement is structured so as to assure that the new plant is constructed on time, on budget and to exacting standards. In ~~April 2008, NINA entered into~~accordance with the EPC agreement, TANE will provide engineering and development services prior to Full Notice to Proceed, or FNTP, on a ~~$20 million revolving loan arrangement, as borrower, to provide working capital to NINA. This facility matures on April 21, 2011,~~time and ~~permits NINA to make cash draws~~materials basis. Upon the New Source Review’s, or ~~issue letters of credit. Borrowings accrue interest at either LIBOR or a base rate, plus a spread. As of September 30, 2008, NINA has $9.5 million outstanding under this facility.~~

~~Toshiba Corporation, or Toshiba, will serve as the prime contractor on all of NINA’s projects, and has agreed to partner with NRG on the NINA venture. Toshiba is currently prime contractor~~NRC approval of the STP units 3 and 4 ~~project~~combined license and ~~is providing licensing support~~the owners decision to issue the FNTP, the EPC converts to a lump-sum turnkey contract with customary warranties, performance and ~~leading all engineering~~schedule guarantees, and ~~scheduling activities, which ultimately will lead~~liquidated damage provisions. TANE’s obligations are backed by a guaranty from its ultimate parent, the Toshiba Corporation. Concurrent with the execution of the EPC agreement, NINA entered into a $500 million credit facility with TANE to ~~responsibility~~finance the cost of material and equipment commitments prior to FNTP for constructing the project. Toshiba will invest $300 million in NINA in six annual installments of $50 million, the last three of which are subject to certain conditions, in exchange for a 12% equity ownership in NINA. Half of this investment will be to fund development activities related to STP units 3 and 4. ~~The other half will be targeted towards developing~~

In light of the progress made by the project in terms of regulatory schedule, DOE loan guarantee process, and ~~deploying additional Advanced Boiling Water Reactor, or ABWR, projects~~the conclusion of the EPC agreement, NINA has initiated a partial sell down process in ~~North America with other potential partners. Toshiba is also extending pre-negotiated Engineering, Procurement and Construction, or EPC, terms to NINA for two additionaltwo-unit~~ ~~nuclear projects similar to the terms being offered for~~ the STP ~~unit~~expansion. NINA has Memorandums of Understanding with a mix of investment grade rated load serving entities and industrial customers for all offtake from NINA’s anticipated 40% ownership interest in STP units 3 and ~~4 development.~~4’s generation. Currently, NINA and CPS Energy each own 50% of the 2,700 megawatt planned expansion of the South Texas Project nuclear facility. After the sell down, it is expected that each would own 40% and a new owner(s) would have a 20% equity interest although other ownership outcomes may arise. The ownership interests of STP units 1 and 2, (NRG 44%, CPS Energy 40% and Austin Energy 16%) are not affected by this proposed sale.

Agreement with eSolar

On February 23, 2009, the Company signed an agreement with eSolar, a leading provider of modular, scalable solar thermal power technology, to acquire the development rights to approximately 500MW of solar thermal power plants at sites in California and the Southwest. The first plant is anticipated to begin producing electricity as early as 2011.

At closing, NRG will invest in approximately $10 million for equity and associated development rights for three projects on sites in south central California and the Southwest US and a portfolio of PPAs to develop, build, own and operate up to 11 eSolar modular solar generating units at these sites. These development assets will use eSolar’s concentrating solar power, or CSP, technology to sell renewable electricity under contracted PPAs with local utilities.

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NINA intends to use the NRC certified ABWR design, with only a limited number of changes to enhance safety and construction schedules. On September 24, 2008, NINA filed a revision to the COLA. Given the changes to the application, RepoweringNRG ~~anticipates STP units 3 and 4 will come online in 2015 and 2016, respectively.~~

~~RepoweringNRG~~ Update

~~Cos Cob~~Currently, NRG has various projects in certain stages of development that includes a biomass project at Montville Generating Station

~~On June 26, 2008, NRG announced the completion of~~ and the repowering of Limestone 3, Big Cajun I and El Segundo sites. As a result of permitting delays related to on-going Natural Resource Defense Counsel claims, the El Segundo project will not reach its ~~Cos Cob generating station in Fairfield County, Connecticut which added 40 MW~~original completion date of ~~power to the site.~~June 1, 2011. The Company ~~funded~~is contemplating certain PPA modifications, including commercial operations date.

The following is a summary of repowering projects that are under construction. In addition, NRG continues to participate in active bids in response to requests for proposals in markets in which it operates, particularly in the West and developed this project which added two new gas turbine units, between the existing three units, bringing total output to 100 MW. All five units were retrofitted to use water injection technology, resulting in a 50% net station reduction in NO_x ~~and a 97% reduction in SO~~₂ ~~emissions by using low-sulfur distillate fuel.~~

Northeast regions.

~~Sherbino I Wind Farm~~Plants under Construction

On October 22, 2008, NRG and its 50/50 joint venture partner, BP Wind Energy North America Inc., or BP, announced the completion of its Sherbino I Wind Farm project in Pecos County, Texas. The wind farm was developed by NRG’s subsidiary Padoma Wind Power LLC, or Padoma. Padoma managed the construction and development, which began in late 2007, and BP will operate and dispatch the facility. Sherbino is a 150 MW wind farm consisting of 50 Vestas wind turbine generators, each capable of generating up to 3 MW of power. Since NRG has a 50 percent ownership, Sherbino will provide the Company a net capacity of 75 MW.

GenConn Energy LLC

~~On March 3,~~— In a procurement process conducted by the Department of Public Utility Control, or DPUC, and finalized in 2008, ~~GenConn Energy LLC, or~~ GenConn, a 50/50 joint venture ~~vehicle~~ of NRG and The United Illuminating Company, ~~submitted a binding bid to the~~secured contracts in 2008 with Connecticut ~~Department of Public Utility Control,~~Light & Power, or ~~DPUC, for new peaking generation facilities in Connecticut subject to a regulated long-term contract. The DPUC subsequently made two awards to GenConn. The first, on June 25, 2008, was~~CL&P, for the construction and operation of ~~approximately~~two 200 MW of peaking ~~generation~~facilities, at NRG’s Devon ~~plant~~and Middletown sites in ~~Milford, Connecticut with~~Connecticut. The contracts, which are structured as contracts for differences for the operation of the new power plants, have a 30-year term and call for commercial operation ~~date~~ of the Devon project by June 1, 2010, and a~~30-year~~ ~~term. The second, on October 6, 2008, was for~~ the ~~construction and operation of approximately 200 MW of peaking generation at NRG’s~~ Middletown ~~facility in Middletown, Connecticut with a commercial operation date of June 1, 2011 and a30-year~~ ~~term. GenConn subsidiaries have executed contracts for differences with Connecticut Light & Power for each of these projects that have been approved by the DPUC.~~

~~El Segundo Energy Center LLC~~

~~On March 7, 2008, NRG, through its wholly-owned subsidiary, El Segundo Energy Center LLC, or ESEC, executed a10-year~~ tolling agreement, or PPA, with Southern California Edison, or SCE. Pre-construction activities started shortly thereafter on a 550 MW rapid response combined cycle facility in El Segundo, California. Since that time, NRG has made non-refundable payments of approximately $17 million to the equipment provider to meet the project ~~construction schedule.~~

~~On July 29, 2008, the Los Angeles County Superior Court issued a ruling in~~~~Natural Resource Defense Council, Inc. v. South Coast Air Management District~~(Case No. BS 110792), or NRDC I, that eliminated the availability of certain air credits from the Priority Reserve program of the South Coast Air Management District, or SCAQMD. On August 18, 2008, the Natural Resource Defense Council, or NRDC, filed a Complaint for Declaratory and Injunctive Relief in the US District Court for the Central District of California (~~Natural Resource Defense Council, Inc. v. South Coast Air Management District~~~~(CaseNo. CV08-05403), or NRCD II, claiming the emission reduction credits created by retiring power generation units and those created by SCAQMD Rule 1309.1 do not meet federal Clean Air Act requirements.~~

If successful, these actions may affect ESEC’s ability to use air emission credits generated by retiring generating units and the distribution of credits from offset accounts. Although the California Public Utilities Commission, or CPUC, approved the PPA on September 18, 2008, the project is unlikely to reach commercial operation by June 1, ~~2011 as a result~~2011. GenConn has secured all state permits required for the projects and has entered into contracts for engineering, construction and procurement of the ~~NRDC I and II related permitting delays.~~

~~Plants under Construction~~8 GE LM6000 combustion turbines required for the projects. As of April 1 2009, construction has begun at the Devon site while construction at Middletown is expected to commence in the first quarter 2010.

~~The Company has two projects under construction, the Cedar Bayou Generating Station and the Elbow Creek~~Langford Wind ~~Farm.~~

~~In August 2007,~~Project— On March 12, 2009, NRG, through its wholly owned subsidiary, ~~NRG Cedar Bayou Development Company~~Padoma Wind Power LLC, ~~entered into a definitive agreement with EnergyCo Cedar Bayou 4, LLC to jointly develop, construct, operate and own,~~began construction on a 50/50 undivided interest basis, a 550 MW combined cycle natural gas turbine generating plant at NRG’s Cedar Bayou Generating Station in Chambers County, Texas. This project is expected to reach commercial operations in mid-2009.

~~On March 27, 2008, NRG, through Padoma, began construction of the Elbow Creek project, a wholly-owned 122~~150 MW wind farm located in ~~Howard County near Big Spring,~~Tom Green, Irion, and Schleicher Counties, Texas. ~~This~~The Langford Wind Project will utilize 100 General Electric 1.5 MW wind turbines. The project is scheduled to reach commercial ~~operations~~operation by the end of ~~2008.~~

~~Huntley IGCC~~

In December 2006, in a competitive bid process with New York Power Authority, or NYPA, NRG won a conditional award of a power purchase agreement in support of the construction of a 600 MW IGCC plant at its existing Huntley facility. The project was cancelled on July 22, 2008.

2009.

Off-Balance Sheet Arrangements

Obligations ~~Under~~under Certain Guarantee Contracts

NRG and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include financial and performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. See Note 17,Guarantees,to this Form 10-Q for additional discussion.

Retained or Contingent Interests

NRG does not have any material retained or contingent interests in assets transferred to an unconsolidated entity.

Derivative Instrument Obligations

~~On August 11, 2005, NRG issued~~The Company’s 3.625% Preferred Stock ~~that included~~includes a ~~conversion~~ feature which is considered aan embedded derivative per ~~FAS 133, as amended.~~SFAS 133. Although it is considered aan embedded derivative, it is exempt from derivative accounting as it is excluded from the scope pursuant to paragraph 11(a) of ~~FAS~~SFAS 133. As of ~~September 30, 2008,~~March 31, 2009, based on the Company’s stock price, the ~~redemption value of this~~ embedded derivative was ~~approximately $2 million.~~out-of-the-money and had no redemption value.

~~On October 13, 2006, NRG, through its~~The Company’s unrestricted wholly-owned ~~subsidiaries, NRG Common Stock Fund I, or CSF I, and NRG Common Stock Fund II, or~~subsidiary, CSF II, ~~issued~~has outstanding notes and preferred interests ~~for the repurchase of NRG’s common stock. Included in each agreement was features~~that contain a feature considered an embedded derivative per SFAS 133. Although it is considered a derivative, it is exempt from derivative accounting as it is excluded from the scope pursuant to paragraph 11(a) of SFAS 133. In August 2008, the Company amended the CSF I notes and preferred interests to early settle the CSF I embedded derivative. Accordingly, NRG made a cash payment of $45 million to CS for the benefit of CSF I, which was recorded to interest expense in the Company’s Consolidated Statement of Operations. As of ~~September 30, 2008,~~March 31, 2009, based on the Company’s stock price, the ~~redemption value on the~~ CSF II embedded derivative was ~~approximately $22 million.~~out-of-the-money and had no redemption value.

Obligations Arising Out of a Variable Interest in an Unconsolidated Entity

Variable ~~interest~~Interest in ~~equity investments~~Equity Investments— As of September 30, 2008, NRG had not entered into any financing structure that was designed to be off-balance sheet that would create incremental liquidity, financing or market risk or credit risk to the Company. However,March 31, 2009, NRG has several investments with an ownership interest percentage of 50% or less in energy and energy-related entities that are accounted for under the equity method of accounting. One of these investments, GenConn, is a variable interest entity for which NRG is not the primary beneficiary.

NRG’s pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately ~~$193~~$122 million as of ~~September 30, 2008.~~March 31, 2009. This indebtedness may restrict the ability of these ~~affiliates~~subsidiaries to issue dividends or distributions to NRG.

In addition, as previously discussed, NRG and BP entered into a 50/50 joint venture in February 2008 to build and own Sherbino. NRG expects to contribute $87 million in equity to the joint venture and has posted a letter of credit in this amount. NRG’s maximum exposure to loss is limited to its expected equity investments.

~~Synthetic~~ Letter of Credit ~~Facility and Revolver Facility~~Facilities— ~~Under NRG’s amended Senior Credit Facility which the Company entered into in June 2007, the Company has a~~The Company’s $1.3 billion Synthetic Letter of Credit Facility ~~which~~is unfunded by NRG and is secured by a $1.3 billion cash deposit at Deutsche Bank AG, New York Branch ~~the Issuing Bank. This deposit~~that was funded using proceeds from the ~~Senior Credit~~Term Loan Facility investors who participated in the facility syndication. Under the Synthetic Letter of Credit Facility, NRG is allowed to issue letters of credit for general corporate purposes including posting collateral to support the Company’s commercial operations activities. Currently NRG has the capability to issue under its Revolving Credit Facility unfunded Letters of Credit up to $900 million for ongoing working capital requirements and for general corporate purposes, including acquisitions that are permitted under the Senior Credit Facility. In addition, NRG is permitted to issue additional letters of credit of up $100 million under the Senior Credit Facility through other financial institutions.

As of September 30, 2008, the Company had issued $766 million in letters of credit under the Synthetic Letter of Credit Facility. The Company had no letters of credit issued under the Revolving Credit Facility as of September 30, 2008. A portion of these letters of credit supports non-commercial letter of credit obligations.

Contractual Obligations and Commercial Commitments

NRG has a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to the Company’s capital expenditure programs, as disclosed in the Company’sForm 10-K. Also see Note 14,Commitments and Contingencies, to the condensed consolidated financial statements of thisForm 10-Q for a discussion of new commitments and contingencies that also include contractual obligations and commercial commitments that occurred during the ~~third~~first quarter ~~2008.~~

2009.

Critical Accounting Policies and Estimates

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

On an ongoing basis, NRG evaluates these estimates, utilizing historic experience, consultation with experts and other methods the Company considers reasonable. In any event, actual results may differ substantially from the Company’s estimates. ~~Any effects~~Effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

Critical accounting policies and estimates are the accounting policies that are most important to the portrayal of NRG’s financial condition and results of operations and require management’s most difficult, subjective or complex judgment. NRG’s critical accounting policies include revenue recognition and derivative accounting, income taxes and valuation allowance for deferred taxes, evaluation of assets for impairment and other than temporary decline in value, goodwill and other intangible assets, and contingencies

7967


~~ITEM 3 —~~	~~QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK~~

ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

NRG is exposed to several market risks in the Company’s normal business activities. Market risk is the potential loss that may result from market changes associated with the Company’s merchant power generation or with an existing or forecasted financial or commodity transaction. The types of market risks the Company is exposed to are commodity price risk, interest rate risk and currency exchange risk. In order to manage these risks the Company uses various fixed-price forward purchase and sales contracts, futures and option contracts traded on the New York Mercantile Exchange, and swaps and options traded in theover-the-counter financial markets to:


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

	•		Manage and hedge exposure to variable rate debt obligations;

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

	•		Hedge fuel requirements for the Company’s generating facilities.

Commodity Price Risk

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


	•		Seasonal, daily and hourly changes in demand;

	•		Extreme peak demands due to weather conditions;

	•		Available supply resources;

	•		Transportation availability and reliability within and between regions; and

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

As part of NRG’s overall portfolio, NRG manages the commodity price risk of the Company’s merchant generation operations by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted sales of electricity and purchases of fuel. These instruments include ~~forward purchase and sale contracts,~~forwards, futures, swaps, and option contracts traded on ~~the~~various exchanges, such as New York Mercantile Exchange, or NYMEX, Intercontinental Exchange, or ICE, and ~~swaps and options traded in the~~Chicago Climate Exchange, or CCX, as well as over-the-counter financial markets. The portion of forecasted transactions hedged may vary based upon management’s assessment of market, weather, operation and other factors.

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

NRG measures the ~~market~~ risk of the Company’s portfolio ~~to commodity prices~~ using several analytical methods, including sensitivity tests, scenario tests, stress tests, position reports, and Value at Risk, or VAR. VAR is a statistical model that attempts to predict risk of loss based on market price and volatility. Currently, the company estimates VAR using a Monte Carlo simulation based methodology. NRG’s total portfolio includesmark-to-market and ~~non-mark-to-market~~non mark-to-market energy assets and liabilities.

NRG uses a diversified VAR model to calculate an estimate of the potential loss in the fair value of the Company’s energy assets and liabilities, which includes generation assets, load obligations, and bilateral physical and financial transactions. The key assumptions for the Company’s diversified model include: (i) a lognormal distribution of ~~prices;~~prices, (ii) one-day holding ~~period;~~period, (iii) a 95% confidence ~~interval;~~interval, (iv) a rolling36-month forward looking ~~period;~~period, and (v) market implied volatilities and historical price correlations.

As of ~~September 30, 2008,~~March 31, 2009, the VAR for NRG’s commodity portfolio, including generation assets, load obligations and bilateral physical and financial transactions calculated using the diversified VAR model was ~~$51~~$35 million.

The following table summarizes average, maximum and minimum VAR for ~~NRG:~~NRG for the three months ended March 31, 2009, and 2008:

(In millions)
VAR 2009 2008

As of March 31, $ 35 $ 43
Average 41 53
Maximum 50 65
Minimum 34 35

(In millions)

VAR (a) 2008 2007

Three months ended September 30: $   51 $   32
Average 48 31
Maximum 62 37
Minimum 35 24

Nine months ended September 30: $ 51 $ 32
Average 50 26
Maximum 65 37
Minimum 35 15

~~(a)~~ ~~Prior to December 4, 2007, NRG’s VAR measurement was based on a rolling24-month~~ ~~forward looking period.~~
Due to the inherent limitations of statistical measures such as VAR, the ~~relative immaturity~~evolving nature of the competitive markets for electricity and related derivatives, and the seasonality of changes in market prices, the VAR calculation may not capture the full extent of commodity price exposure. As a result, actual changes in the fair value ofmark-to-market energy assets and liabilities could differ from the calculated VAR, and such changes could have a material impact on the Company’s financial results.

In order to provide additional information for comparative purposes to NRG’s peers, the Company also uses VAR to estimate the potential loss of derivative financial instruments that are subject tomark-to-market accounting. These derivative instruments include transactions that were entered into for both asset management and trading purposes. The VAR for the derivative financial instruments calculated using the diversified VAR model as of ~~September 30, 2008,~~March 31, 2009, for the entire term of these instruments entered into for both asset management and trading, was approximately ~~$16 million.~~
$41 million primarily driven by asset-backed transactions.
Interest Rate Risk

NRG is exposed to fluctuations in interest rates through the Company’s issuance of fixed rate and variable rate debt. Exposures to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combination of the variable rate debt and the interest rate derivative instrument. NRG’s risk management policies allow the Company to reduce interest rate exposure from variable rate debt obligations.

As of ~~September 30, 2008,~~March 31, 2009, the Company had various interest rate swap agreements with notional amounts totaling approximately ~~$2.6~~$2.4 billion. If the swaps had been discontinued on ~~September 30, 2008,~~March 31, 2009, the Company would have owed the counterparties approximately ~~$74~~$141 million. Based on ~~a diverse group~~the investment grade rating of the counterparties, NRG believes its exposure to credit risk due to nonperformance by counterparties to its hedge contracts to be insignificant. In addition, due to the fact that the interest rate environment at that time was lower than the interest rates in NRG’s interest rate swaps, NRG could then engage in new interest rate swaps at improved rates in the event of default by its counterparties.

NRG has both ~~long-~~long and short-term debt instruments that subject the Company to the risk of loss associated with movements in market interest rates. As of ~~September 30, 2008,~~March 31, 2009, a ~~100 basis point~~1% change in interest rates would result in a ~~$13~~$11 million change in interest expense on a rolling twelve month basis.

As of ~~September 30, 2008,~~March 31, 2009, the Company’s long-term debt fair value was ~~$7.2~~$7.3 billion and the carrying amount was ~~$8.0~~$7.8 billion. NRG estimates that a 1% decrease in market interest rates would have increased the fair value of the Company’s long-term debt by ~~$420~~$386 million.

81

Liquidity Risk

Liquidity risk arises from the general funding needs of NRG’s activities and in the management of the Company’s assets and liabilities. NRG’s liquidity management framework is intended to maximize liquidity access and minimize funding costs. Through active liquidity management, the Company seeks to preserve stable, reliable and cost-effective sources of funding. This enables the Company to replace maturing obligations when due and fund assets at appropriate maturities and rates. To accomplish this task, management uses a variety of liquidity risk measures that take into consideration market conditions, prevailing interest rates, liquidity needs, and the desired maturity profile of liabilities.

Based on a sensitivity analysis, a $1 per MMBtu increase or decrease in natural gas prices across the term of the marginable contracts for power and gas positions would cause a change in margin collateral outstanding of approximately ~~$69~~$72 million as of ~~September 30, 2008.~~March 31, 2009. In addition, a 0.25 MMBtu/MWh change in heat rates for heat rate positions would result in a change in margin collateral of approximately $62 million as of March 31, 2009. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of ~~September 30, 2008.~~March 31, 2009.

Under the second lien, NRG is required to post certain letters of credit as credit support for changes in commodity prices. As of March 31, 2009, no letters of credit are outstanding to second lien counterparties. With changes in commodity prices, the letters of credit could grow to $87 million, the cap under the agreements.

Credit Risk

~~A sharp~~Under the current economic downturn in the US and overseas, markets during the latter part of 2008 was prompted by a combination of factors: tight credit markets, speculation and fear over the health of the US and global financial systems, and weaker economic activity in general prompting fears of an economic recession. Under the current market dynamics, the Company has heightened its management and mitigation of counterparty credit risk by using credit limits, netting agreements, collateral thresholds, volumetric limits and other mitigation measures, where available. NRG avoids concentration of counterparties whenever possible and applies credit policies that include an evaluation of counterparties’ financial condition, collateral requirements and the use of standard agreements that allow for netting and other security.

The following table highlights the credit quality and the net counterparty credit exposure ~~(net of collateral) to NRG, or Net Exposure,~~ by industry ~~sector and by credit quality. Counterparty~~sector. Net counterparty credit exposure is ~~NRG’s~~defined as the aggregate net ~~in-the-money~~asset position for ~~a counterparty after giving effect to any~~NRG with counterparties where netting ~~that~~ is permitted under the enabling ~~agreements~~agreement and includes all cash flow, mark to market and normal purchase and sale and non-derivative transactions. AsThe exposure is shown net of ~~September 30, 2008, aggregate counterparty credit exposure to substantially all counterparties was $1.2 billion~~collateral held, and ~~NRG held collateral (cash and letters~~includes amounts net of ~~credit) against those positions of $236 million resulting in aggregate Net Exposure of $1.0 billion.~~receivables or payables.


	Net Exposure^(a) as of
	March 31, 2009
Category	(% of Total)

Coal ~~producers~~suppliers		422	%
Financial institutions		32	%	63
Utilities, energy, merchants, marketers and ~~marketers~~other		17	%	32
ISOs		9	%	3


Total ~~as of September 30, 2008~~		100	%


	Net Exposure^(a) as of March 31, 2009
Category	(% of Total)

Investment grade		5295	%
Non-Investment grade		27	%	1
Non-rated		21	%	4


Total ~~as of September 30, 2008~~		100	%

(a)
~~(a)~~		~~Excludes~~Credit exposure excludes California tolling, uranium, coal transportation/railcar leases, New England Reliability ~~Must Run,~~Must-Run, cooperative load contracts and Texas Westmoreland coal contracts.

~~NRG’s Net Exposure~~ NRG has credit risk exposure to ~~those~~certain counterparties ~~individually~~ representing more than 10% of ~~its~~ total ~~Net Exposure~~net exposure and the aggregate of such counterparties was ~~$252 million in the aggregate.~~$444 million. No single counterparty represents more than ~~15%~~19% of total ~~Net Exposure.~~net credit exposure. Approximately ~~three-quarters~~85% of NRG’s ~~Net Exposure rolls off~~positions relating to credit risk roll-off by the end of ~~2010.~~2011. Changes in hedge positions and market prices will affect ~~Net Exposure~~credit exposure and counterparty concentration. Given the credit quality, diversification and term of the exposure in the portfolio, NRG does not anticipate ~~any~~a material ~~adverse effect~~impact on the Company’s financial ~~position or~~ results ~~of operations as a result of~~from nonperformance by ~~any of NRG’s counterparties.~~a counterparty.

Fair Value of Derivative Instruments

NRG may enter into long-term power sales contracts, fuel purchase contracts and other energy-related financial instruments to mitigate variability in earnings due to fluctuations in spot market prices, to hedge fuel requirements at generation facilities and protect fuel inventories. In addition, in order to mitigate interest rate risk associated with the issuance of the Company’s variable rate and fixed rate debt, NRG enters into interest rate swap agreements.

NRG’s trading activities include contracts ~~entered into~~ to profit from market price changes as opposed to hedging an exposure, and are subject to limits in accordance with the Company’s risk management policy. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings. These trading activities are a complement to NRG’s energy marketing portfolio.

The tables below disclose the activities that include ~~all derivative~~both exchange and non-exchange traded contracts accounted for at fair value. Specifically, these tables disaggregate realized and unrealized changes in fair value; identify changes in fair value attributable to changes in valuation techniques; disaggregate estimated fair values ~~as of September 30, 2008,~~at March 31, 2009, based on whether fair values are determined by quoted market prices or more subjective means; and indicate the maturities of ~~contracts:~~contracts at March 31, 2009.


Derivative Activity Gains/(Losses)	(In millions)

Fair value of contracts as of December 31, 2008	$	996
Contracts realized or otherwise settled during the period		(249	)
Changes in fair value		843

Fair value of contracts as of March 31, 2009	$	1,590

Fair Value of Contracts as of March 31, 2009
Maturity Maturity
(In millions) Less Than Maturity Maturity in Excess Total Fair
Sources of Fair Value Gains/(Losses) 1 Year 1-3 Years 4-5 Years 4-5 Years Value

Prices actively quoted $ 37 $ 14 $ — $ — $ 51
Prices provided by other external sources 735 442 273 (37 ) 1,413
Prices provided by models and other valuation methods 90 23 13 — 126

Total $ 862 $ 479 $ 286 $ (37 ) $ 1,590

Derivative Activity Losses (In millions)

Fair value of contracts as of December 31, 2007 $   (492 )
Contracts realized or otherwise settled during the period 163
Changes in fair value 155

Fair value of contracts as of September 30, 2008 $ (174 )

Fair Value of Contracts as of September 30, 2008
Maturity
Maturity

(In millions)
Less than
Maturity
Maturity
in excess
Total Fair

Sources of Fair Value Gains/(Losses) 1 Year 1-3 Years 4-5 Years 5 Years Value

Prices actively quoted $ (8 ) $ 7 $ — $ — $ (1 )
Prices provided by other external sources 162 (323 ) (19 ) (12 ) (192 )
Prices provided by models and other valuation methods 13 5 1 — 19

Total $   167 $   (311 ) $   (18 ) $   (12 ) $   (174 )

A small portion of NRG’s contracts are exchange-traded contracts with readily available quoted market prices. The majority of NRG’s contracts are non exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers orover-the-counter and on-line exchanges. For the majority of NRG markets, the Company receives quotes from multiple sources. To the extent that NRG receives multiple quotes, the Company’s prices reflect the average of the bid-ask mid-point prices obtained from all sources that NRG believes provide the most liquid market for the commodity. If the Company ~~only~~ receives one quote then the ~~mid-point~~mid point of the bid-ask spread for that quote is used. The terms for which such price information is available vary by commodity, region and product. The remainder of the assets and liabilities represent contracts for which external sources or observable market quotes are not available. These contracts are valued based on various valuation techniques including but not limited to internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Contracts valued with prices provided by models and other valuation techniques make up ~~11%~~8% of the total fair value of all derivative contracts. The fair value of each contract is discounted using a risk free interest rate.
In addition, the Company applies a credit reserve to reflect credit risk which is calculated based on published default probabilities. To the extent that NRG’s net exposure under a specific master agreement is an asset, the Company is using the counterparty’s ~~risk of default.~~default swap rate. If the exposure under a specific master agreement is a liability, the Company is using NRG’s ~~probability of default.~~default swap rate. The credit reserve is added to the discounted fair value to reflect the exit price that a market participant would be willing to receive to assume NRG’s liabilities or that a market participant would be willing to pay for NRG’s assets. As of ~~September 30, 2008~~March 31, 2009, the credit reserve resulted in a $6$46 million decrease in fair value which is composed of a $5$23 million ~~gain~~loss in OCI and ~~an $11~~a $23 million loss in derivative ~~revenue.~~revenue and cost of operations.
     The fair values in each category reflect the level of forward prices and volatility factors as of ~~September 30, 2008~~March 31, 2009, and may change as a result of changes in these factors. Management uses its best estimates to determine the fair value of commodity and derivative contracts NRG holds and sells. These estimates consider various factors including closing exchange andover-the-counter price quotations, time value, volatility factors and credit exposure. It is possible however, that future market prices could vary from those used in recording assets and liabilities from energy marketing and trading activities and such variations could be material.

8371

The Company has elected to disclose derivative activity on atrade-by-trade basis and does not offset amounts at the counterparty master agreement level. Consequently, the magnitude of the changes in individual current and non-current derivative assets or liabilities is higher than the underlying credit and market risk of the Company’s portfolio. As discussed in ~~the~~ Item 37A— Commodity Price Risk~~section above,~~, NRG measures the sensitivity of the Company’s portfolio to potential changes in market prices using Value at Risk, or VAR, a statistical model which attempts to predict risk of loss based on market price and volatility. NRG’s ~~Risk Management Policy~~risk management policy places a limit onone-day holding period VAR, which limits the Company’s net open position. ~~However,~~As the Company’strade-by-trade derivative accounting results in agross-up of the Company’s derivative assets and ~~liabilities. Thus,~~liabilities, the net derivative assets and liability position is a better indicator of ~~our~~NRG’s hedging activity. As of ~~September 30, 2008,~~March 31, 2009, NRG’s net derivative ~~liability~~asset was ~~$174 million,~~$1.6 billion, an increase to total fair value of ~~$318~~$594 million as compared to December 31, ~~2007.~~2008. This increase was primarily driven by decreases in gas and power prices as well as the ~~roll off~~roll-off of ~~deals~~trades that settled during the period.

Currency Exchange Risk

NRG may be subject to foreign currency risk as a result of the Company entering into purchase commitments with foreign vendors for the purchase of major equipment associated with~~RepoweringNRG~~ RepoweringNRG initiatives. To reduce the risks to such foreign currency exposure, the Company may enter into transactions to hedge its foreign currency exposure using currency options and forward contracts. ~~At September 30, 2008,~~As of March 31, 2009, there were no foreign currency options orand forward contracts ~~outstanding. Due~~outstanding for purchase commitments.

In addition, in connection with the MIBRAG sale, the Company entered into a foreign currency forward contract on March 12, 2009 to hedge the impact of exchange rate fluctuations on the sale proceeds. The foreign currency forward contract has a fixed exchange rate of 1.277. The contract requires NRG to pay EUR 200 million in exchange for $255 million on June 30, 2009.

As a result of the Company’s limited foreign currency exposure to date, the effect of foreign currency fluctuations has not been material to the Company’s results of operations, financial position and cash flows as of ~~September 30, 2008.~~and for the three months ended March 31, 2009.


~~ITEM 4 —~~	~~CONTROLS AND PROCEDURES~~

~~Evaluation~~ITEM 4 — CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision and with the participation of ~~the Company’s~~NRG’s management, including its principal executive officer, principal financial officer and principal accounting officer, ~~the Company~~NRG conducted an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures, as such term is defined inRules 13a-15(e) and15d-15(e) of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Based on this evaluation, the Company’s principal executive officer, principal financial officer and principal accounting officer concluded that the disclosure controls and procedures were effective as of the end of the period covered by this report onForm 10-Q.

Changes in Internal ~~Control~~Controls over Financial Reporting

There ~~have been~~were no changes in the Company’s internal ~~control~~controls over financial reporting (as such term is defined inRules 13a-15(f) ~~and15d-15(f)~~ under the Exchange Act) ~~during~~that occurred in the ~~current period covered by this report onForm 10-Q~~first quarter of 2009 that ~~have~~ materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Inherent Limitations over Internal Controls

NRG’s internal ~~control~~controls over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with generally accepted accounting principles. However, internal ~~control~~controls over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations, including the possibility of human error and circumvention by collusion or overriding of controls. Accordingly, even an effective internal control system may not prevent or detect material misstatements on a timely basis. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

8472

PART II — OTHER INFORMATION
ITEM 1 — LEGAL PROCEEDINGS

~~ITEM 1 —~~ ~~LEGAL PROCEEDINGS~~
For a discussion of material legal proceedings in which NRG was involved through ~~September 30, 2008,~~March 31, 2009, see Note 14,Commitments and Contingencies, to the condensed consolidated financial statements of thisForm 10-Q.
ITEM 1A — RISK FACTORS

~~ITEM 1A —~~ ~~RISK FACTORS~~
~~Information~~In addition to the revised risk factor below, information regarding risk factors appears in Part I, Item 1A, Risk Factors in NRG Energy, Inc.’s ~~2007~~2008 Annual Report onForm 10-K for the fiscal year ended December 31, ~~2007.~~2008.
If Exelon Corporation’s board expansion proposal is approved at NRG’s 2009 annual shareholders meeting and all of Exelon Corporation’s nominees are elected to NRG’s Board of Directors at the meeting, there will be an increased risk of a change of control under NRG’s debt instruments, and if that were to occur the Company could become obligated to immediately repay approximately $8 billion under the Senior Credit Facility and Senior Notes, which would likely have a material adverse affect on NRG’s business and financial condition and could render us insolvent.

~~ITEM 2 —~~ ~~UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS~~
~~Item 2(c) —~~ ~~Purchase of Equity securities by NRG~~

Total number of shares
Dollar value of

purchased as part of
shares that may be

Total number of
Average price
publicly announced
purchased under the

For the period ended October 27, 2008 shares purchased paid per share plans or programs plans or programs

First Quarter 2008 Total 1,281,600 $ 42.73 1,281,600 $      160,008,401

Second Quarter 2008 Total — — — 160,008,401

July 1 — July 31 — — — —
August 1 — August 31 3,410,283 38.06 3,410,283 30,226,541
September 1 — September 31 — — — —

Third Quarter 2008 Total 3,410,283 38.06 3,410,283 30,226,541

October 1 — October 27, 2008 — — — —

Year-to-date 4,691,883 $   39.33 4,691,883 $ 30,266,541

~~On February 28, 2008, NRG announced~~Under NRG’s Senior Credit Facility and the indentures governing NRG’s Senior Notes, a ~~$300 million stock buyback as part~~“change of control” is deemed to occur if, among other triggering events, “a majority of the ~~Company’s 2008 Capital Allocation Program. As discussed~~members of the Board of Directors of NRG are not continuing directors.” A “continuing director” is defined to mean, as of the date of determination, any director who was a member of NRG’s Board on the date of NRG’s Senior Credit Facility or the indenture governing NRG’s Senior Notes, as the case may be, or was nominated for election or elected to NRG’s Board with the approval of a majority of the “continuing directors” who were members of NRG’s Board at the time of such nomination or election. Based on NRG’s interpretation of this provision, the failure of a majority of NRG’s directors to qualify as “continuing directors” would result in ~~Note 8,~~~~Changes in Capital Structure~~,a change of control. Since Exelon’s proposal, the NRG Board has added two members and currently consists of 14 members, all of whom qualify as “continuing directors.” If Exelon Corporation’s board expansion proposal passes and all of its nominees are elected to NRG’s Board, NRG’s Board would consist of 19 members, 10 of whom would be existing NRG directors who qualify as “continuing directors” and nine of whom would be directors nominated by Exelon Corporation who would not qualify as “continuing directors.” Therefore, under NRG’s interpretation of the change of control provision, a change of control would be triggered by any future event that reduces the number of continuing directors, such as the retirement or death of any such director. If a change of control were triggered under NRG’s Senior Credit Facility, an event of default would occur and the bank lenders under the facility would have the right to accelerate the outstanding indebtedness under the facility, which, as of March 31, 2009, totaled $2.4 billion, and if a change of control were triggered under the indentures governing NRG’s Senior Notes, note holders holding approximately $4.7 billion face amount of the notes would have the right to put the notes to the Company ~~initiated its 2008 program in December 2007.~~at 101% of par. If either or both of these events were to occur, it would likely have a material adverse impact on NRG’s business and financial condition and could render us insolvent. In addition to adding the two new Board members, the Company and the NRG Board may continue to explore other options to mitigate this risk.
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
     None.
~~ITEM 3 —~~ ~~DEFAULTS UPON SENIOR SECURITIES~~
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES
     None.
ITEM 4 — SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
     None.
ITEM 5 — OTHER INFORMATION
     None.
73

~~None.~~
~~ITEM 4 —~~ ~~SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS~~
~~None.~~
~~ITEM 5 —~~ ~~OTHER INFORMATION~~
~~None.~~

85
ITEM 6 — EXHIBITS
~~ITEM 6 —~~Exhibits ~~EXHIBITS~~
10.1* LLC Membership Purchase Agreement between Reliant Energy, Inc. and NRG Retail LLC, dated as of February 28, 2009.
10.2
Credit Agreement by and among Nuclear Innovation North America LLC, Nuclear Innovation North America Investments LLC, NINA Texas 3 LLC and NINA Texas 4 LLC, as Borrowers and Toshiba America Nuclear Energy Corporation, as Administrative Agent and as Collateral Agent⁽¹⁾
31.1 Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
31.2 Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
31.3 Certification of Chief Accounting Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
32 Certification of Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, filed herewith.
* Portions of this exhibit have been redacted and are subject to a confidential treatment request filed with the Securities and Exchange Commission pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended.
(1) Incorporated herein by reference to NRG Energy Inc’s current report on Form 8-K filed on February 27, 2009.
74

Exhibits

3 .1 Second Certificate of Amendment to Certificate of Designations relating to the Series 1 Exchangeable Limited Liability Company Preferred Interests of NRG Common Stock Finance I LLC, as filed with the Secretary of State of Delaware on August 8, 2008.
10 .1 Amendment Agreement, dated August 8, 2008, to the Note Purchase Agreement by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.
10 .2 Preferred Interest Amendment Agreement, dated August 8, 2008, by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.
31 .1 Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
31 .2 Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
31 .3 Certification of Chief Accounting Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
32 Certification of Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, filed herewith.

86
SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
~~NRG ENERGY, INC.~~
~~(Registrant)~~
NRG ENERGY, INC.
(Registrant)
/s/ DAVID W. CRANE
David W. Crane
Chief Executive Officer
(Principal Executive Officer)

/s/ ~~DAVID W. CRANE~~ROBERT C. FLEXON
Robert C. Flexon
Chief Financial Officer
(Principal Financial Officer)
/s/ JAMES J. INGOLDSBY
James J. Ingoldsby
Date: April 30, 2009 Chief Accounting Officer
(Principal Accounting Officer)
75
~~David W. Crane~~
~~Chief Executive Officer~~
~~(Principal Executive Officer)~~

~~/s/~~  ~~CLINT C. FREELAND~~
~~Clint C. Freeland~~
~~Chief Financial Officer~~
~~(Principal Financial Officer)~~
~~/s/ JAMES J. INGOLDSBY~~
~~James J. Ingoldsby~~
~~Chief Accounting Officer~~
~~(Principal Accounting Officer)~~
~~Date: October 30, 2008~~

87
EXHIBIT INDEX
Exhibits
10.1* LLC Membership Purchase Agreement between Reliant Energy, Inc. and NRG Retail LLC, dated as of February 28, 2009.
10.2
Credit Agreement by and among Nuclear Innovation North America LLC, Nuclear Innovation North America Investments LLC, NINA Texas 3 LLC and NINA Texas 4 LLC, as Borrowers and Toshiba America Nuclear Energy Corporation, as Administrative Agent and as Collateral Agent⁽¹⁾
31.1 Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
31.2 Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
31.3 Certification of Chief Accounting Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
32 Certification of Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, filed herewith.

Exhibits

3 .1 Second Certificate of Amendment to Certificate of Designations relating to the Series 1 Exchangeable Limited Liability Company Preferred Interests of NRG Common Stock Finance I LLC, as filed with the Secretary of State of Delaware on August 8, 2008.
10 .1 Amendment Agreement, dated August 8, 2008, to the Note Purchase Agreement by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.
10 .2 Preferred Interest Amendment Agreement, dated August 8, 2008, by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.
31 .1 Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
31 .2 Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
31 .3 Certification of Chief Accounting Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
32 Certification of Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, filed herewith.
* Portions of this exhibit have been redacted and are subject to a confidential treatment request filed with the Securities and Exchange Commission pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended.
(1) Incorporated herein by reference to NRG Energy Inc’s current report on Form 8-K filed on February 27, 2009.

8876


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

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


~~Acquisition~~APB		~~February 2, 2006 acquisition of Texas Genco LLC, now referred to as the Company’s Texas region~~Accounting Principles Board
~~ABWR~~APB 18		~~Advanced Boiling Water Reactor~~
~~ANPR~~		~~Advanced Notice~~APB Opinion No. 18,“The Equity Method of ~~Proposed Rulemaking~~
~~ARO~~		~~Asset Retirement Obligation~~
~~BACT~~		~~Best Available Control Technology~~Accounting for Investments in Common Stock”
Baseload ~~Capacity~~capacity		Electric power generation capacity normally expected to serve loads on an around-the-clock basis throughout the calendar year
BPBTA		~~BP Alternative Energy North America Inc.~~Best Technology Available
BTU		British Thermal Unit
CAA		Clean Air Act
CAGR		Compound annual growth rate
CAIR		Clean Air Interstate Rule
~~CAMR~~CAISO		~~Clean Air Mercury Rule~~California Independent System Operator
Capital Allocation Plan		Share repurchase program
Capital Allocation Program		NRG’s plan of allocating capital between debt reduction, reinvestment in the business, and share repurchases through the Capital Allocation Plan
CDWR		California Department of Water Resources
CL&P		The Connecticut Light & Power Company
CO₂		Carbon dioxide
~~COLA~~		~~Combined Operating License Application~~
CS		Credit Suisse Group
CSF I		NRG Common Stock Finance I LLC
CSF II		NRG Common Stock Finance II LLC
CSRA		Credit sleeve facility with Merrill Lynch in connection with acquisition of Reliant Retail, as hereinafter defined
DNREC		Delaware Department of Natural Resources and Environmental Control
DPUC		~~Connecticut~~ Department of Public Utility Control
EAF		Annual Equivalent Availability Factor, which measures the percentage of maximum generation available over time as the fraction of net maximum generation that could be provided over a defined period of time after all types of outages and deratings, including seasonal deratings, are taken into account
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 07-5		EITF No. 07-5, “Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock”
EITF 08-5		EITF 08-5, “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement”
EITF 08-6		EITF 08-6, “Equity Method Investment Accounting Considerations”
EPC		Engineering, Procurement and Construction
ERCOT		Electric Reliability Council of Texas, the Independent System Operator and the ~~regional reliability coordinator~~Regional Reliability Coordinator of the various electricity systems within Texas
ESPP		Employee Stock Purchase Plan
Exchange Act		The Securities Exchange Act of 1934, as amended
Expected Baseload Generation		The net baseload generation 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
FCM		Forward Capacity Market
FERC		Federal Energy Regulatory Commission
FIN		FASB Interpretation
FIN 4818		FIN No. 18,“Accounting for Income Taxes in Interim Periods”
FIN 48		FIN No. 48, “Accounting for Uncertainty in Income ~~Taxes~~Taxes”
FPA		Federal Power Act
Fresh Start		Reporting requirements as defined by SOP 90-7
FSP		FASB Staff Position
FSP APB 14-1		FSP No. APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement)”
FSP FAS 107-1 and APB 28-1		FSP No. FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments”
FSP FAS 132R-1		FSP No. FAS 132(R)-1,“Employers’ Disclosures about Postretirement Benefit Plan Assets”

		~~For~~
o		Transition report pursuant to Section 13 or 15(d) of the ~~quarterly period ended: September 30, 2008~~Securities Exchange Act of 1934


					Page No.
				~~No.~~

CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION		3
GLOSSARY OF TERMS		4
PART I	—		FINANCIAL INFORMATION		78
ITEM 1	—		CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES		78
ITEM 2	—		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		42
ITEM 3	—		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		8068
ITEM 4	—		CONTROLS AND PROCEDURES		8472
PART II — OTHER INFORMATION	—		~~OTHER INFORMATION~~		8573
ITEM 1	—		LEGAL PROCEEDINGS		8573
ITEM 1A	—		RISK FACTORS		8573
ITEM 2	—		UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		8573
ITEM 3	—		DEFAULTS UPON SENIOR SECURITIES		8573
ITEM 4	—		SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS		8573
ITEM 5	—		OTHER INFORMATION		8573
ITEM 6 — EXHIBITS	—		~~EXHIBITS~~		8674
SIGNATURES		8775
~~EX-3.1: SECOND CERTIFICATE OF AMENDMENT TO CERTIFICATE OF DESIGNATIONS~~EX-10.1
~~EX-10.1: NOTE PURCHASE AMENDMENT AGREEMENT~~EX-31.1
~~EX-10.2: PREFERRED INTEREST AMENDMENT AGREEMENT~~EX-31.2
~~EX-31.1: CERTIFICATION~~EX-31.3
~~EX-31.2: CERTIFICATION~~
~~EX-31.3: CERTIFICATION~~
~~EX-32: CERTIFICATION~~EX-32


	Three Months Ended September 30							Nine Months Ended September 30

(In millions, except for per share amounts)		2008			2007			2008			2007

Operating Revenues
Total operating revenues		$	2,690		$	1,772		$	5,308		$	4,607


Operating Costs and Expenses
Cost of operations			997			939			2,812			2,560
Depreciation and amortization			156			160			478			481
General and administrative			75			78			233			234
Development costs			13			49			29			108


Total operating costs and expenses			1,241			1,226			3,552			3,383
Gain on sale of assets			—			—			—			16


Operating Income			1,449			546			1,756			1,240


Other Income/(Expense)
Equity in earnings of unconsolidated affiliates			58			19			35			40
Other (loss)/income, net			(7	)		14			14			44
Refinancing expense			—			—			—			(35	)
Interest expense			(186	)		(169	)		(481	)		(520	)


Total other expense			(135	)		(136	)		(432	)		(471	)


Income From Continuing Operations Before Income Taxes			1,314			410			1,324			769
Income tax expense			530			145			531			300


Income From Continuing Operations			784			265			793			469
Income from discontinued operations, net of income tax expense			—			3			172			13


Net Income			784			268			965			482
Dividends for preferred shares			13			13			41			41


Income Available for Common Stockholders		$	771		$	255		$	924		$	441
Weighted average number of common shares outstanding — basic			235			239			236			241
Income from continuing operations per weighted average common share — basic		$	3.28		$	1.05		$	3.19		$	1.78
Income from discontinued operations per weighted average common share — basic			—			0.02			0.73			0.05


Net Income per Weighted Average Common Share — Basic		$	3.28		$	1.07		$	3.92		$	1.83


Weighted average number of common shares outstanding — diluted			277			285			278			287
Income from continuing operations per weighted average common share — diluted		$	2.83		$	0.92		$	2.83		$	1.61
Income from discontinued operations per weighted average common share — diluted			—			0.01			0.62			0.05


Net Income per Weighted Average Common Share — Diluted		$	2.83		$	0.93		$	3.45		$	1.66


	September 30, 2008			December 31, 2007

(In millions, except shares)	(unaudited)

ASSETS
Current Assets
Cash and cash equivalents	$	1,483		$	1,132
Restricted cash		32			29
Accounts receivable, less allowance for doubtful accounts of $3 and $1, respectively		531			482
Inventory		456			451
Derivative instruments valuation		4,190			1,034
Deferred income taxes		—			124
Cash collateral paid in support of energy risk management activities		544			85
Prepayments and other current assets		203			174
Current assets — discontinued operations		—			51


Total current assets		7,439			3,562


Property, plant and equipment, net of accumulated depreciation of $2,184 and $1,695, respectively		11,472			11,320


Other Assets
Equity investments in affiliates		428			425
Notes receivable and capital lease, less current portion		450			491
Goodwill		1,786			1,786
Intangible assets, net of accumulated amortization of $425 and $372, respectively		822			873
Nuclear decommissioning trust fund		333			384
Derivative instruments valuation		816			150
Other non-current assets		134			176
Intangible assets held-for-sale		3			14
Non-current assets — discontinued operations		—			93


Total other assets		4,772			4,392


Total Assets	$	23,683		$	19,274


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	122		$	466
Accounts payable		367			384
Derivative instruments valuation		4,022			917
Deferred income taxes		16			—
Cash collateral received in support of energy risk management activities		154			14
Accrued expenses and other current liabilities		629			459
Current liabilities — discontinued operations		—			37


Total current liabilities		5,310			2,277


Other Liabilities
Long-term debt and capital leases		8,059			7,895
Nuclear decommissioning reserve		320			307
Nuclear decommissioning trust liability		252			326
Deferred income taxes		1,083			843
Derivative instruments valuation		1,158			759
Out-of-market contracts		336			628
Other non-current liabilities		568			412
Non-current liabilities — discontinued operations		—			76


Total non-current liabilities		11,776			11,246


Total Liabilities		17,086			13,523


Minority interest		7			—
3.625% convertible perpetual preferred stock (at liquidation value, net of issuance costs)		247			247
Commitments and Contingencies
Stockholders’ Equity
Preferred stock (at liquidation value, net of issuance costs)		892			892
Common stock		3			3
Additional paid-in capital		4,135			4,092
Retained earnings		2,194			1,270
Less treasury stock, at cost — 29,242,483 and 24,550,600 shares, respectively		(823	)		(638	)
Accumulated other comprehensive loss		(58	)		(115	)


Total Stockholders’ Equity		6,343			5,504


Total Liabilities and Stockholders’ Equity	$	23,683		$	19,274


~~Note 5 —~~	~~Nuclear Decommissioning Trust Fund~~


~~Note 6 —~~	~~Accounting for Derivative Instruments and Hedging Activities~~


(In millions)	Energy			Interest
Three months ended September 30, 2008	Commodities			Rate			Total

Accumulated OCI balance at June 30, 2008	$	(1,235	)	$	(30	)	$	(1,265	)
Realized from OCI during the period:
— Due to realization of previously deferred amounts		26			—			26
Mark-to-market of hedge contracts		1,088			(2	)		1,086


Accumulated OCI balance at September 30, 2008	$	(121	)	$	(32	)	$	(153	)


Gains expected to be realized from OCI during the next 12 months, net of $53 tax	$	81		$	—		$	81


	Authorized		Issued		Treasury			Outstanding

Balance as of December 31, 2007		500,000,000		261,285,529		(24,550,600	)		236,734,929
2008 Capital Allocation Program		—		—		(4,691,883	)		(4,691,883	)
Shares issued from LTIP		—		984,176		—			984,176


Balance as of September 30, 2008		500,000,000		262,269,705		(29,242,483	)		233,027,222


						Aggregate
				Weighted		Intrinsic
				Average		Value
	Shares			Exercise Price		(In millions)

Outstanding as of December 31, 2007		3,579,775		$	19.98
Granted		1,174,200			40.48
Forfeited		(148,536	)		32.79
Exercised		(507,986	)		16.29


Outstanding at September 30, 2008		4,097,453			25.84	$	—
Exercisable at September 30, 2008		2,056,803		$	17.54		15


				Weighted
				Average
				Grant-Date
				Fair Value
	Units			Per Unit

Non-vested as of December 31, 2007		1,588,316		$	26.99
Granted		163,200			40.22
Vested		(610,760	)		19.38
Forfeited		(71,320	)		31.13


Non-vested as of September 30, 2008		1,069,436		$	33.08


				Weighted
				Average
				Grant- Date
				Fair Value
	Units			Per Unit

Non-vested as of December 31, 2007		536,764		$	20.18
Granted		227,300			27.75
Vested		(50,000	)		15.74
Forfeited		(59,700	)		21.49


Non-vested as of September 30, 2008		654,364		$	23.05



	Three months ended September 30,						Nine months ended September 30,
(In millions, except per share data)	2008			2007			2008			2007

*Basic earnings per share*
Numerator:
Income from continuing operations	$	784		$	265		$	793		$	469
Preferred stock dividends		(13	)		(13	)		(41	)		(41	)


Net income available to common stockholders from continuing operations		771			252			752			428
Discontinued operations, net of income tax expense		—			3			172			13


Net income available to common stockholders	$	771		$	255		$	924		$	441


Denominator:
Weighted average number of common shares outstanding		234.8			239.4			235.7			240.5
*Basic earnings per share:*
Income from continuing operations	$	3.28		$	1.05		$	3.19		$	1.78
Discontinued operations, net of income tax expense		—			0.02			0.73			0.05


Net income	$	3.28		$	1.07		$	3.92		$	1.83


*Diluted earnings per share*
Numerator:
Net income available to common stockholders from continuing operations	$	771		$	252		$	752		$	428
Add preferred stock dividends for dilutive preferred stock		11			11			34			34


Adjusted income from continuing operations available to common shareholders		782			263			786			462
Discontinued operations, net of tax		—			3			172			13


Net income available to common stockholders	$	782		$	266		$	958		$	475


Denominator:
Weighted average number of common shares outstanding		234.8			239.4			235.7			240.5
Incremental shares attributable to the issuance of equity compensation (treasury stock method)		2.2			3.8			3.0			3.7
Incremental shares attributable to embedded derivatives of certain financial instruments (if-converted method)		2.0			4.6			1.8			4.9
Incremental shares attributable to assumed conversion features of outstanding preferred stock (if-converted method)		37.5			37.5			37.5			37.5


Total dilutive shares		276.5			285.3			278.0			286.6
*Diluted earnings per share:*
Income from continuing operations available to common shareholders	$	2.83		$	0.92		$	2.83		$	1.61
Income from discontinued operations, net of tax		—			0.01			0.62			0.05


Net income	$	2.83		$	0.93		$	3.45		$	1.66


	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions of shares)	2008		2007		2008		2007

Equity compensation		1.8		—		1.4		0.4
Embedded derivative of 3.625% convertible perpetual preferred stock		14.0		13.2		14.2		13.0
Embedded derivative of preferred interests and notes issued by CSF I and CSF II		8.3		16.7		8.3		16.6


Total		24.1		29.9		23.9		30.0


	Wholesale Power Generation
(In millions)					South
Three Months Ended September 30, 2008	Texas		Northeast		Central		West		International		Thermal		Corporate			Elimination			Total

Operating revenues	$	1,661	$	677	$	233	$	40		$ 41	$	36	$	3		$	(1	)	$	2,690
Depreciation and amortization		108		26		16		2		—		3		1			—			156
Equity in earnings of unconsolidated affiliates		40		—		—		1		17		—		—			—			58
Income/(loss) from continuing operations before income taxes		1,050		351		24		13		25		4		(152	)		(1	)		1,314
Income from discontinued operations, net of income taxes		—		—		—		—		—		—		—			—			—


Net income/(loss)	$	594	$	351	$	24	$	13		$ 19	$	4	$	(220	)	$	(1	)	$	784


Total assets	$	12,102	$	1,634	$	942	$	53		$ 1,002	$	212	$	19,006		$	(11,268	)	$	23,683


(In millions except percentages)
Nine Months Ended September 30,	2008			2007

Income from continuing operations before income taxes	$	1,324		$	769


Tax at 35%		463			269
State taxes		62			37
Valuation allowance		(1	)		1
Foreign operations		(10	)		(5	)
Foreign dividend		5			21
Non-deductible interest		24			7
Change in German tax rate		—			(30	)
Section 199 Manufacturing Deduction		(17	)		(3	)
Other permanent differences including subpart F income		5			3


Income tax expense	$	531		$	300


Effective income tax rate		40.1	%		39.0	%


~~Note 13 —~~	~~Benefit Plans and Other Postretirement Benefits~~


	Defined Benefit Pension Plans
	Three Months Ended September 30,						Nine Months Ended September 30,

(In millions)	2008			2007			2008			2007

Service cost benefits earned	$	4		$	3		$	11		$	11
Interest cost on benefit obligation		4			4			13			13
Net gain		—			—			(1	)		—
Expected return on plan assets		(4	)		(3	)		(11	)		(9	)


Net periodic benefit cost	$	4		$	4		$	12		$	15


	Other Postretirement Benefits Plans
	Three Months Ended September 30,				Nine Months Ended September 30,

(In millions)	2008		2007		2008		2007

Service cost benefits earned	$	1	$	1	$	2	$	2
Interest cost on benefit obligation		1		2		4		4


Net periodic benefit cost	$	2	$	3	$	6	$	6


	Preferred Stock		Conversion Rate		Common Stock
	Shares		(per share)		Shares

Balance as of December 31, 2008		1,841,680				—
Preferred shares converted by the holders prior to March 16, 2009		144,975		8.2712		1,199,116
Preferred shares automatically converted as of March 16, 2009		1,696,705		10.2564		17,402,085

Balance at March 31, 2009		—				18,601,201


				Weighted		Aggregate Intrinsic
				Average		Value
	Shares			Exercise Price		(In millions)

Outstanding as of December 31, 2008		4,008,188		$	25.84
Granted		1,195,600			23.64
Forfeited		(8,967	)		29.77

Outstanding at March 31, 2009		5,194,821			25.33	$	7
Exercisable at March 31, 2009		2,801,309		$	21.56		7


				Weighted Average
				Grant-Date
	Units			Fair Value Per Unit

Non-vested as of December 31, 2008		1,061,996		$	32.97
Granted		147,000			23.64
Vested		(288,578	)		23.73
Forfeited		(10,720	)		39.55

Non-vested as of March 31, 2009		909,698		$	34.32


				Weighted Average
				Grant- Date
	Units			Fair Value Per Unit

Non-vested as of December 31, 2008		659,564		$	22.81
Granted		285,200			22.73
Forfeited		(216,064	)		18.72

Non-vested as of March 31, 2009		728,700		$	24.16


	Wholesale Power Generation
(In millions)					South
Three months ended March 31, 2009	Texas		Northeast		Central		West			International		Thermal		Corporate			Elimination			Total

Operating revenues	$	925	$	464	$	162	$	28		$	34	$	42	$	4		$	(1	)	$	1,658
Depreciation and amortization		117		29		17		2			—		2		2			—			169
Equity in earnings of unconsolidated affiliates		4		—		—		1			17		—		—			—			22
Income/(loss) from continuing operations before income taxes		378		211		1		(3	)		14		4		(109	)		—			496

Net income attributable to NRG Energy, Inc.	$	217	$	211	$	1	$	(3	)	$	12	$	4	$	(244	)	$	—		$	198

Total assets	$	13,298	$	1,687	$	929	$	262		$	952	$	206	$	19,966		$	(13,102	)	$	24,198


	Defined Benefit Pension
(In millions)	Plans
Three months ended March 31,	2009			2008

Service cost benefits earned	$	4		$	4
Interest cost on benefit obligation		5			5
Expected return on plan assets		(4	)		(4	)

Net periodic benefit cost	$	5		$	5


	Other Postretirement
(In millions)	Benefits Plans
Three months ended March 31,	2009		2008

Service cost benefits earned	$	1	$	1
Interest cost on benefit obligation		2		1

Net periodic benefit cost	$	3	$	2


~~Note 18 —~~	~~Condensed Consolidating Financial Information~~


Arthur Kill Power LLC		NRG Construction LLC
Astoria Gas Turbine Power LLC		NRG Devon Operations Inc.
Berrians I Gas Turbine Power LLC		NRG Dunkirk Operations, Inc.
Big Cajun II Unit 4 LLC		NRG El Segundo Operations Inc.
Cabrillo Power I LLC		NRG Generation Holdings, Inc.
Cabrillo Power II LLC		NRG Huntley Operations Inc.
Chickahominy River Energy Corp.		NRG International LLC
Commonwealth Atlantic Power LLC		NRG Kaufman LLC
Conemaugh Power LLC		NRG Mesquite LLC
Connecticut Jet Power LLC		NRG MidAtlantic Affiliate Services Inc.
Devon Power LLC		NRG Middletown Operations Inc.
Dunkirk Power LLC		NRG Montville Operations Inc.
Eastern Sierra Energy Company		NRG New Jersey Energy Sales LLC
El Segundo Power, LLC		NRG New Roads Holdings LLC
El Segundo Power II LLC		NRG North Central Operations, Inc.
GCP Funding Company LLC		NRG Northeast Affiliate Services Inc.
Hanover Energy Company		NRG Norwalk Harbor Operations Inc.
Hoffman Summit Wind Project LLC		NRG Operating Services Inc.
Huntley IGCC LLC		NRG Oswego Harbor Power Operations Inc.
Huntley Power LLC		NRG Power Marketing LLC
Indian River IGCC LLC		NRG Rocky Road LLC
Indian River Operations Inc.		NRG Saguaro Operations Inc.
Indian River Power LLC		NRG South Central Affiliate Services Inc.
James River Power LLC		NRG South Central Generating LLC
Kaufman Cogen LP		NRG South Central Operations Inc.
Keystone Power LLC		NRG South Texas LP
Lake Erie Properties Inc.		NRG Texas LLC
Louisiana Generating LLC		NRG Texas Power LLC
Middletown Power LLC		NRG West Coast LLC
Montville IGCC LLC		NRG Western Affiliate Services Inc.
Montville Power LLC		Oswego Harbor Power LLC
NEO Chester-Gen LLC		Padoma Wind Power, LLC
NEO Corporation		Saguaro Power LLC
NEO Freehold-Gen LLC		San Juan Mesa Wind Project II, LLC
NEO Power Services Inc.		Somerset Operations Inc.
New Genco GP LLC		~~Somerset Power LLC~~


Norwalk Power LLC		~~Texas Genco Financing Corp.~~Somerset Power LLC
NRG Affiliate Services Inc.		Texas Genco ~~GP, LLC~~Financing Corp.
NRG Arthur Kill Operations Inc.		Texas Genco ~~Holdings, Inc.~~GP, LLC
NRG Asia-Pacific Ltd.		Texas Genco ~~LP, LLC~~Holdings, Inc.
NRG Astoria Gas Turbine Operations Inc.		Texas Genco ~~Operating Services,~~LP, LLC
NRG Bayou Cove LLC		Texas Genco Operating Services, LLC
NRG Cabrillo Power Operations Inc.		Texas Genco Services, LP
NRG ~~Cabrillo Power~~Cadillac Operations Inc.		Vienna Operations, Inc.
NRG ~~Cadillac Operations Inc.~~		~~Vienna Power LLC~~
~~NRG~~ California Peaker Operations LLC		~~WCP (Generation) Holdings~~Vienna Power LLC
NRG Cedar Bayou Development Company LLC		~~West Coast Power~~WCP (Generation) Holdings LLC
NRG Connecticut Affiliate Services Inc.		West Coast Power LLC


							NRG Energy,															NRG Energy,
	Guarantor			Non-Guarantor			Inc.						Consolidated			Guarantor			Non-Guarantor			Inc.						Consolidated
(In millions)	Subsidiaries			Subsidiaries			(Note Issuer)			Eliminations (a)			Balance			Subsidiaries			Subsidiaries			(Note Issuer)			Eliminations (a)			Balance

Operating Revenues
Total operating revenues	$	2,597			$ 111			$ —			$ (18	)		$ 2,690		$	1,566		$	95		$	—		$	(3	)	$	1,658


Operating Costs and Expenses
Cost of operations		919			99			(3	)		(18	)		997			698			68			3			(3	)		766
Depreciation and amortization		148			7			1			—			156			158			10			1			—			169
General and administrative		16			14			45			—			75			17			3			75			—			95
Development costs		2			2			9			—			13			2			2			9			—			13


Total operating costs and expenses		1,085			122			52			(18	)		1,241			875			83			88			(3	)		1,043


Operating Income/(Loss)		1,512			(11	)		(52	)		—			1,449			691			12			(88	)		—			615
Other Income/(Expense)
Equity in earnings/(losses) of consolidated subsidiaries		52			—			897			(949	)		—
Equity in earnings of consolidated subsidiaries																	21			—			397			(418	)		—
Equity in earnings of unconsolidated affiliates		1			57			—			—			58			1			21			—			—			22
Other income/(expense), net		4			11			(22	)		—			(7	)
Other income/(loss), net																	1			(7	)		3			—			(3	)
Interest expense		(46	)		(61	)		(79	)		—			(186	)		(48	)		(21	)		(69	)		—			(138	)


Total other income/(expense)		11			7			796			(949	)		(135	)		(25	)		(7	)		331			(418	)		(119	)

Income/(Losses) From Continuing Operations Before Income Taxes																	666			5			243			(418	)		496
Income tax expense																	252			1			45			—			298

Income/(Losses) From Continuing Operations Before Income Taxes		1,523			(4	)		744			(949	)		1,314
Income tax expense/(benefit)		532			38			(40	)		—			530
Net Income attributable to NRG Energy, Inc.																$	414		$	4		$	198		$	(418	)	$	198


Income/(Losses) From Continuing Operations		991			(42	)		784			(949	)		784
Income/(Losses) from discontinued operations, net of income taxes		—			—			—			—			—


Net Income/(Loss)	$	991			$(42	)		$ 784			$ (949	)		$784


(a)		All significant intercompany transactions have been eliminated in consolidation.

Large accelerated filerþ

Accelerated filero

Non-accelerated filero

Smaller reporting companyo

(Do not check if a smaller reporting company)