UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

þ		Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

o		Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended: September 30, 2007                  Commission File Number: 001-15891

NRG Energy, Inc.
(Exact name of Registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)		41-1724239 (I.R.S. Employer Identification No.)
211 Carnegie Center Princeton, New Jersey (Address of principal executive offices)		08540 (Zip Code)

(609) 524-4500
(Registrant’s telephone number, including area code)

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer (as defined in Rule 12 b-2 of the Exchange Act).

Large accelerated filer þ      Accelerated filer o      Non-accelerated filer o

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

     Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15 (d) of the Securities and Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.

     As of October 31, 2007, there were 238,653,519 shares of common stock outstanding, par value $0.01 per share.

 

 

TABLE OF CONTENTS
Index

		Page No.
CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION			3
GLOSSARY OF TERMS			4
Part I — FINANCIAL INFORMATION			6
Item 1 — Condensed Consolidated Financial Statements and Notes			6
Item 2 — Management’s Discussion and Analysis of Financial Conditions and Results of Operations			39
Item 3 — Quantitative and Qualitative Disclosures About Market Risk			71
Item 4 — Controls and Procedures			75
PART II — OTHER INFORMATION			76
Item 1 — Legal Proceedings			76
Item 1A — Risk Factors			76
Item 2 — Unregistered Sales of Equity Securities and Use of Proceeds			76
Item 3 — Defaults upon Senior Securities			76
Item 4 — Submission of Matters to a Vote of Securities Holders			76
Item 5 — Other Information			76
Item 6 — Exhibits			77
Exhibit Index			77
SIGNATURES			78
Exhibit Index			79
EX-31.1: CERTIFICATION
EX-31.2: CERTIFICATION
EX-31.3: CERTIFICATION
EX-32: CERTIFICATION

CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION

     This Quarterly Report on Form 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 Energy Inc.’s, or 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 on Form 10-K and Part II, Item 1A, of NRG’s Quarterly Report on Form 10-Q and 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 (including general and administrative expenses), and generate earnings and cash flows from its asset-based businesses in relation to its debt and other obligations;
	•		NRG’s potential inability 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 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 its RepoweringNRG strategy of developing and building new power generation facilities, including new nuclear units and Integrated Gasification Combined Cycle, or IGCC, units; and
	•		NRG’s ability to achieve the expected benefits of its Comprehensive Capital Allocation Plan and Holdco structure.

     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 on Form 10-Q should not be construed as exhaustive.

GLOSSARY OF TERMS

     When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:

Acquisition		February 2, 2006 acquisition of Texas Genco LLC, now referred to as the Company’s Texas region
Baseload capacity		Electric power generation capacity normally expected to serve loads on an around-the-clock basis throughout the calendar year
BTU		British Thermal Unit
CAISO		California Independent System Operator
Capital Allocation Program		Share repurchase program entered into in August 2006
CDD		Cooling Degree Day — It represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in a region
CDWR		California Department of Water Resources
CL&P		Connecticut Light & Power
CO2		Carbon Dioxide
COLA		Combined Construction and Operating License Application
Comprehensive Capital Allocation Plan		A comprehensive plan to support and facilitate NRG’s capital allocation strategy that includes a holding company structure to enable the distribution of a cash dividend on NRG’s common stock, the pay down of debt, a stock split, and the Capital Allocation Program
CPUC		California Public Utilities Commission
DOJ		Department of Justice
DNREC		Delaware Department of Natural Resources and Environmental Control
EAB		Environmental Appeals Board
EPC		Engineering, Procurement and Construction
ERCOT		Electric Reliability Council of Texas, the Independent System Operator and regional reliability coordinator of the various electricity systems within Texas
FASB		Financial Accounting Standards Board, the designated organization for establishing standards for financial accounting and reporting
FERC		Federal Energy Regulatory Commission
FIN		FASB Interpretation
GAAP		Accounting principles generally accepted in the United States
GHG		Greenhouse Gases
HDD		Heating Degree Day — It represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in a region
Hedge Reset		Net settlement of long-term power contracts and gas swaps by negotiating prices to current market completed in November 2006
ICAP		Installed Capacity
IGCC		Integrated Gasification Combined Cycle
ISO		Independent System Operator, also referred to as Regional Transmission Organization, or RTO
ITISA		Itiquira Energetica S.A.
kW		Kilowatts
LFRM		Locational Forward Reserve Market
LIBOR		London Inter-Bank Offered Rate
Merit Order		A term used for the ranking of power stations in terms of increasing order of fuel costs
MMBtu		Million British Thermal Units
MW		Megawatts
MWh		Saleable megawatt hours net of internal/parasitic load
NEPOOL		New England Power Pool
New York Rest of State		New York State excluding New York City
NiMo		Niagara Mohawk Power Corporation
NOx		Nitrogen oxide
NOL		Net Operating Loss
NOV		Notice of Violation
NPNS		Normal Purchase Normal Sale
NQSO		Non-Qualified Stock Options
NSR		Non-Spinning Reserve
NYISO		New York Independent System Operator
OCI		Other Comprehensive Income
Phase II 316(b) Rule		A section of the Clean Water Act regulating cooling water intake structures

		GLOSSARY OF TERMS (cont’d)
PJM		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, Inc., a wholly-owned subsidiary of NRG which procures transportation and fuel for NRG’s generation facilities, sells the power from these facilities, and manages all commodity trading and hedging for NRG
PPA		Power Purchase Agreement
PU		Performance Units
PUCT		Public Utility Commission of Texas
RepoweringNRG		Our 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		Reliability Must-Run
RPM		Reliability Pricing Model
RSU		Restricted Stock Units
RTO		Regional Transmission Organization, also referred to as an ISO
SEC		United States Securities and Exchange Commission
Senior Credit Facility		NRG’s senior secured facility, which is comprised of a $3.1 billion Term B loan facility which matures on February 1, 2013, its $1.3 billion Synthetic Letter of Credit Facility, and its $1 billion Revolving Credit Facility
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 the $1.1 billion of 7.375% senior notes due 2017
SFAS		Statement of Financial Accounting Standards issued by the FASB
SFAS 5		SFAS No. 5, “Accounting for Contingencies”
SFAS 71		SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation”
SFAS 109		SFAS No. 109, “Accounting for Income Taxes”
SFAS 133		SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”
SO2		Sulfur Dioxide
STP		South Texas Project — Nuclear generating facility located near Bay City, Texas in which NRG owns a 44% interest
Synthetic Letter of Credit Facility		NRG’s $1.3 billion senior secured synthetic letter of credit facility which matures on February 1, 2013
Term B loan		$3.1 billion bank term loan included as part of NRG’s Senior Credit Facility
TEP		Temporary Extraordinary Operating Procedures
Texas Genco		Texas Genco LLC, now referred to as the Company’s Texas region
TWCC		Texas Westmoreland Coal Company
U.S.		United States of America
USEPA		United States Environmental Protection Agency
VAR		Value at Risk
WCP		WCP (Generation) Holdings, LLC

PART I — FINANCIAL INFORMATION

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)		2007				2006				2007				2006
Operating Revenues
Total operating revenues		$	1,786			$	1,942			$	4,644			$	4,479
Operating Costs and Expenses
Cost of operations			943				996				2,570				2,478
Depreciation and amortization			161				148				483				443
General and administrative			79				70				236				205
Development costs			49				9				108				15
Total operating costs and expenses			1,232				1,223				3,397				3,141
Gain on sale of assets			—				—				16				—
Operating Income			554				719				1,263				1,338
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates			19				17				40				46
Write downs and gains/(losses) on sales of equity method investments			—				(3	)			1				8
Other income, net			15				30				45				118
Refinancing expense			—				—				(35	)			(178	)
Interest expense			(173	)			(154	)			(528	)			(420	)
Total other expense			(139	)			(110	)			(477	)			(426	)
Income From Continuing Operations Before Income Taxes			415				609				786				912
Income Tax Expense			147				238				304				324
Income From Continuing Operations			268				371				482				588
Income from discontinued operations, net of income tax expense			—				51				—				63
Net Income			268				422				482				651
Dividends for Preferred Shares			13				14				41				37
Income Available for Common Stockholders		$	255			$	408			$	441			$	614
Weighted Average Number of Common Shares Outstanding — Basic			239				272				241				261
Income From Continuing Operations per Weighted Average Common Share — Basic		$	1.07			$	1.31			$	1.83			$	2.11
Income From Discontinued Operations per Weighted Average Common Share — Basic			—				0.19				—				0.24
Net Income per Weighted Average Common Share — Basic		$	1.07			$	1.50			$	1.83			$	2.35
Weighted Average Number of Common Shares Outstanding — Diluted			285				317				287				303
Income From Continuing Operations per Weighted Average Common Share — Diluted		$	0.93			$	1.16			$	1.66			$	1.92
Income From Discontinued Operations per Weighted Average Common Share — Diluted			—				0.16				—				0.21
Net Income per Weighted Average Common Share — Diluted		$	0.93			$	1.32			$	1.66			$	2.13

See notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS

		September 30, 2007				December 31, 2006
(in millions, except for share data)		(unaudited)
ASSETS
Current Assets
Cash and cash equivalents		$	1,171			$	795
Restricted cash			62				44
Accounts receivable, less allowance for doubtful accounts of $1 and $1			536				372
Inventory			424				421
Derivative instruments valuation			827				1,230
Deferred income taxes			45				—
Prepayments and other current assets			284				221
Total current assets			3,349				3,083
Property, plant and equipment, net of accumulated depreciation of $1,515 and $984			11,413				11,600
Other Assets
Equity investments in affiliates			409				344
Notes receivable and capital lease, less current portion			490				479
Goodwill			1,785				1,789
Intangible assets, net of accumulated amortization of $351 and $259			898				981
Nuclear decommissioning trust fund			373				352
Derivative instruments valuation			214				439
Deferred income taxes			30				27
Other non-current assets			152				262
Intangible assets held-for-sale			91				79
Total other assets			4,442				4,752
Total Assets		$	19,204			$	19,435
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases		$	129			$	130
Accounts payable			356				332
Derivative instruments valuation			696				964
Deferred income taxes			—				164
Accrued expenses and other current liabilities			429				442
Total current liabilities			1,610				2,032
Other Liabilities
Long-term debt and capital leases			8,619				8,647
Nuclear decommissioning reserve			302				289
Nuclear decommissioning trust liability			323				324
Deferred income taxes			824				554
Derivative instruments valuation			486				351
Out-of-market contracts			697				897
Other non-current liabilities			471				435
Total non-current liabilities			11,722				11,497
Total Liabilities			13,332				13,529
Minority Interest			1				1
3.625% Redeemable 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				1
Additional paid-in capital			4,032				4,476
Retained earnings			1,180				739
Less treasury stock, at cost — 22,512,900 and 29,601,162 shares			(553	)			(732	)
Accumulated other comprehensive income			70				282
Total Stockholders’ Equity			5,624				5,658
Total Liabilities and Stockholders’ Equity		$	19,204			$	19,435

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,		2007				2006
Cash Flows from Operating Activities
Net income		$	482			$	651
Adjustments to reconcile net income to net cash provided by operating activities
Distributions less than equity in earnings of unconsolidated affiliates			(23	)			(27	)
Depreciation and amortization of nuclear fuel			525				490
Amortization and write-off of financing costs and debt discount/premiums			59				71
Amortization of intangibles and out-of-market contracts			(112	)			(393	)
Amortization of stock-based compensation			19				13
Changes in deferred income taxes			232				309
Changes in derivatives			41				(183	)
Changes in nuclear decommissioning trust liability			23				9
Changes in collateral deposits supporting energy risk management activities			(107	)			397
Gain on legal settlement			—				(67	)
Gain on sale of emission allowances			(31	)			(68	)
(Gain)/loss on sale of assets			(16	)			3
Gain on sale of discontinued operations			—				(71	)
Write down and gains on sale of equity method investments			(1	)			(8	)
Cash provided/(used) by changes in other working capital, net of acquisition and disposition affects			(115	)			40
Net Cash Provided by Operating Activities			976				1,166
Cash Flows from Investing Activities
Acquisition of Texas Genco LLC, WCP and Padoma, net of cash acquired			—				(4,336	)
Capital expenditures			(309	)			(159	)
Increase in restricted cash, net			(18	)			(24	)
Decrease in notes receivable			26				22
Purchases of emission allowances			(152	)			(76	)
Proceeds from sale of emission allowances			170				97
Investments in nuclear decommissioning trust fund securities			(193	)			(158	)
Proceeds from sale of nuclear decommissioning trust fund securities			170				149
Proceeds from sale of assets			57				1
Proceeds from sale of investments			2				86
Decrease in trust fund balances			19				—
Investments in marketable securities			(4	)			—
Proceeds from sale of discontinued operations			—				239
Net Cash Used in Investing Activities			(232	)			(4,159	)
Cash Flows from Financing Activities
Payment of dividends to preferred stockholders			(41	)			(37	)
Payment of financing element of acquired derivatives			—				(118	)
Payment for treasury stock			(268	)			(297	)
Funded letter of credit			—				350
Proceeds from issuance of common stock, net of issuance costs			—				986
Proceeds from issuance of preferred shares, net of issuance costs			—				486
Proceeds from issuance of long-term debt			1,411				7,373
Payment of deferred debt issuance costs			(5	)			(174	)
Payments for short and long-term debt			(1,472	)			(4,697	)
Net Cash Provided/(Used) by Financing Activities			(375	)			3,872
Change in cash from discontinued operations			—				14
Effect of exchange rate changes on cash and cash equivalents			7				2
Net Increase in Cash and Cash Equivalents			376				895
Cash and Cash Equivalents at Beginning of Period			795				493
Cash and Cash Equivalents at End of Period		$	1,171			$	1,388

See notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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 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 and certain international markets.

     The accompanying unaudited interim consolidated financial statements have been prepared in accordance with the United States Securities and Exchange Commission’s, or SEC’s, regulations for interim financial information and with the instructions to Form 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 consolidated financial statements in its Annual Report on Form 10-K for the year ended December 31, 2006, or Form 10-K. The following notes should be read in conjunction with such policies and other disclosures in the Form 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, 2007, results of operations for the three and nine months ended September 30, 2007 and 2006, and cash flows for the nine months ended September 30, 2007 and 2006. Certain prior-year amounts have been reclassified for comparative purposes.

     Stock Split

     On April 25, 2007, NRG’s Board of Directors approved a two-for-one stock split of the Company’s outstanding shares of common stock which was effected through a stock dividend. The stock split entitled each stockholder of record at the close of business on May 22, 2007 to receive one additional share for every outstanding share of common stock held. The additional shares resulting from the stock split were distributed by the Company’s transfer agent on May 31, 2007. All share and per share amounts in the consolidated results of operations and financial position as well as in the notes to the financial statements retroactively reflect the effect of the stock split.

     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.

     Recent Accounting Developments

     In April 2007, the Financial Accounting Standards Board, or FASB, issued FASB Staff Position FIN 39-1, Amendment of FASB Interpretation No. 39, or FSP FIN 39-1, which amends FIN 39, Offsetting of Amounts Related to Certain Contracts. FSP FIN 39-1 impacts entities that enter into master netting arrangements as part of their derivative transactions. Under the guidance in this new 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. FSP FIN 39-1 is effective for fiscal years beginning after November 15, 2007, with early application permitted. The Company does not presently offset derivative positions under master netting arrangement under FIN 39 or FSP FIN 39-1 and is assessing the impact that implementing FIN 39 and FSP FIN 39-1 may have on its consolidated financial position.

     The Company adopted FASB Interpretation Number 48, Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109, or FIN 48, on January 1, 2007. FIN 48 applies to all tax positions related to income taxes subject to SFAS 109, and requires a new evaluation process for all tax positions taken, recognizing tax benefits when it is more likely than not that a tax position will be sustained upon examination by the authorities. The benefit from a position that has surpassed the more likely than not threshold is the largest amount of benefit that is more than 50% likely to be realized upon settlement. The adoption of FIN 48 did not

have a material impact on the Company’s financial position, results of operations and cash flows. The Company recognizes interest and penalties accrued related to unrecognized tax benefits as a component of income tax expense.

     Effective July, 1, 2007, the Company adopted the Emerging Issues Task Force, or EITF, Topic D-109, Determining the Nature of a Host Contract Related to a Hybrid Financial Instrument Issued in the Form of a Share under FASB Statement No.133. This Topic conveys the SEC staff’s views on determining whether the characteristics of a host contract in a hybrid financial instruments issued in the form of a share is more like debt or equity. The SEC staff believes that in evaluating an embedded derivative feature for separation under FASB Statement 133, the consideration of the economic characteristics and risks of the host contract should not ignore the stated or implied substantive terms and features of the hybrid financial instrument. The adoption of Topic D-109 did not have an impact on the Company’s financial position, results of operations, or cash flows.

Note 2 — Comprehensive Income

		Three months ended September 30								Nine months ended September 30
(In millions)		2007				2006				2007				2006
Net Income		$	268			$	422			$	482			$	651
Unrealized gain/(loss) from derivative activity, net of tax			46				28				(278	)			332
Foreign currency translation adjustment			39				(2	)			65				35
Changes in pension liability, net of tax			—				7				—				7
Unrealized gain on available-for-sale securities, net of tax			—				—				1				—
Other comprehensive income/(loss), net of tax		$	85			$	33			$	(212	)		$	374
Comprehensive income		$	353			$	455			$	270			$	1,025

     Accumulated other comprehensive income as of September 30, 2007 was as follows:

(In millions)
Accumulated other comprehensive income as of December 31, 2006		$	282
Unrealized loss from derivative activity, net of tax			(278	)
Foreign currency translation adjustment			65
Unrealized gain on available-for-sale securities, net of tax			1
Accumulated other comprehensive income as of September 30, 2007		$	70

Note 3 — Business Acquisitions and Dispositions

     Acquisition of Remaining 50% interest in WCP

     On March 31, 2006, NRG completed purchase and sale agreements for projects co-owned with Dynegy, Inc. Under the agreements, NRG acquired Dynegy’s 50% ownership interest in WCP (Generation) Holdings, LLC, or WCP, for $205 million in cash and the assumption of a $1 million liability, with NRG becoming the sole owner of WCP’s 1,825 MW of generation capacity in Southern California. In addition, NRG sold to Dynegy the Company’s 50% ownership interest in Rocky Road Power LLC, or Rocky Road, a 330 MW gas-fired, simple cycle peaking plant located in Dundee, Illinois. NRG sold Rocky Road for a fair value sale price of $45 million, paying Dynegy a net purchase price of $160 million at closing. Prior to the purchase, NRG’s existing investment in WCP, the Original Investment, was accounted for as an equity method investment.

     The acquisition of the remaining 50% interest in WCP, or New Investment, was accounted for as a step acquisition since the Original Investment was transacted in a prior period. As a result, the value of the Original Investment and the purchase price of the New Investment were determined and allocated separately. The value of the Original Investment was based on the book value of approximately $159 million as of the date of the acquisition of the New Investment.

     The value of the New Investment was allocated based on the fair value of assets acquired and liabilities assumed as of March 31, 2006. The purchase price allocation reflected an excess of fair value of the net assets acquired over the purchase price of the New Investment, resulting in negative goodwill of approximately $48 million. The negative goodwill was subsequently allocated as a reduction to the fair value of WCP’s fixed and intangible assets.

     The following summarizes the purchase price and allocation impact of the WCP acquisition as of March 31, 2006:

						New Investment
						Fair Value before								Fair Value after
		Original				Negative Goodwill				Allocation of				Negative Goodwill				Purchase Price
(In millions)		Investment				Allocation				Negative Goodwill				Allocation				Allocation
Current assets		$	149			$	153			$	—			$	153			$	302
Property, plant and equipment			24				103				(38	)			65				89
Intangible assets			2				26				(10	)			16				18
Other non-current assets			—				9				—				9				9
Current liabilities			(13	)			(18	)			—				(18	)			(31	)
Non-current liabilities			(3	)			(19	)			—				(19	)			(22	)
Negative goodwill			—				(48	)			48				—				—
Total Equity		$	159			$	206			$	—			$	206			$	365

     Other Business Events

     Red Bluff and Chowchilla — On January 3, 2007, NRG completed the sale of the Company’s Red Bluff and Chowchilla II power plants to an entity controlled by Wayzata Investment Partners LLC. These power plants, located in California, are fueled by natural gas, with generating capacity of 45 MW and 49 MW, respectively. The sale resulted in a pre-tax gain of approximately $18 million.

Note 4 — 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.

     NRG had no business operations that were classified as discontinued operations for the three and nine months ended September 30, 2007. For the three and nine months ended September 30, 2006, discontinued operations consisted of activity related to the Company’s Resource Recovery, Flinders and Audrain operations.

     Summarized results of operations of discontinued entities were as follows:

		Three months ended September 30								Nine months ended September 30
(In millions)		2007				2006				2007				2006
Operating revenues		$	—			$	39			$	—			$	184
Pre-tax loss from operations of discontinued operations			—				(13	)			—				(9	)
Income from discontinued operations, net of income tax expense			—				51				—				63

Note 5 — Nuclear Decommissioning Trust Fund

     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 or 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. As of September 30, 2007, NRG believes the trust funds are adequately funded.

     The following table summarizes the fair values of the securities held in the trust funds as of September 30, 2007 and December 31, 2006:

(In millions) As of		September 30, 2007				December 31, 2006
Cash and cash equivalents		$	3			$	7
U.S. government and federal agency obligations			6				29
Federal agency mortgage-backed securities			43				41
Commercial mortgage-backed securities			18				16
Corporate debt securities			30				43
Marketable equity securities			273				216
Total		$	373			$	352

Note 6 — Accounting for Derivative Instruments and Hedging Activities

     SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, or 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, and subsequently recognize in earnings when the hedged transaction occurs. The ineffective portion of a cash flow hedge is immediately recognized in earnings.

     Accumulated OCI

     The following table summarizes the effects of SFAS 133 on NRG’s accumulated OCI balance attributable to hedged derivatives for the three months ended September 30, 2007, net of tax:

		Energy				Interest
(In millions)		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	)
Gains expected to be realized from OCI during the next 12 months		$	39			$	—			$	39

     The following table summarizes the effects of SFAS 133 on NRG’s accumulated OCI balance attributable to hedged derivatives for the nine months ended September 30, 2007, net of tax:

		Energy				Interest
(In millions)		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	)

     The following table summarizes the effects of SFAS 133 on NRG’s accumulated OCI balance attributable to hedged derivatives for the three months ended September 30, 2006, net of tax:

		Energy				Interest
(In millions)		Commodities				Rate				Total
Accumulated OCI balance at June 30, 2006		$	29			$	79			$	108
Realized from OCI during the period:
— Due to realization of previously deferred amounts			—				1				1
Mark-to-market of hedge contracts			92				(65	)			27
Accumulated OCI balance at September 30, 2006		$	121			$	15			$	136

     The following table summarizes the effects of SFAS 133 on NRG’s accumulated OCI balance attributable to hedged derivatives for the nine months ended September 30, 2006, net of tax:

		Energy				Interest
(In millions)		Commodities				Rate				Total
Accumulated OCI balance at December 31, 2005		$	(204	)		$	8			$	(196	)
Realized from OCI during the period:
— Due to realization of previously deferred amounts			26				(2	)			24
Mark-to-market of hedge contracts			299				9				308
Accumulated OCI balance at September 30, 2006		$	121			$	15			$	136

     As of September 30, 2007, the net balance in OCI relating to SFAS 133 was an unrecognized loss of approximately $69 million, which is net of $46 million in income taxes. NRG expects $39 million of net deferred gains on derivative instruments accumulated in OCI to be recognized in earnings during the next twelve months.

     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 non-hedge derivatives or derivative activities that do not qualify as hedges, and ineffectiveness of hedge derivatives on NRG’s statement of operations for the three and nine months ended September 30, 2007 and 2006, respectively:

		Three months ended September 30								Nine months ended September 30
(In millions)		2007				2006				2007				2006
Revenue from operations — energy commodities		$	6			$	183			$	(41	)		$	300
Interest expense – interest rate swaps			—				—				—				(3	)
Total impact to statement of operations		$	6			$	183			$	(41	)		$	297

     For the three months ended September 30, 2007, the unrealized gain associated with changes in the fair value of derivative instruments not accounted for as hedge derivatives of $6 million was comprised of a $13 million gain from trading activity partially offset by a $7 million loss from economic hedges. The loss from economic hedges includes a $7 million gain due to ineffectiveness related to gas swaps and collars reflecting a change in the correlation between natural gas and power prices as of September 30, 2007.

     For the nine months ended September 30, 2007, the unrealized loss associated with changes in the fair value of derivative instruments not accounted for as hedge derivatives of $41 million was comprised of a $55 million loss from economic hedges partially offset by a $14 million gain from trading activity. The loss from economic hedges includes a $28 million gain due to ineffectiveness related to gas swaps and collars reflecting a change in the correlation between natural gas and power prices.

     For the three months ended September 30, 2006, the unrealized gain associated with changes in the fair value of derivative instruments not accounted for as hedge derivatives of $183 million was comprised of a $198 million gain from economic hedges partially offset by a $15 million loss from trading activity. The gain from economic hedges includes a $78 million gain due to ineffectiveness related to gas swaps and collars reflecting a change in the correlation between natural gas and power prices.

     For the nine months ended September 30, 2006, the unrealized gain associated with changes in the fair value of derivative instruments not accounted for as hedge derivatives of $300 million was comprised of $310 million gain from economic hedges partially offset by a $10 million loss from trading activity. The gain from economic hedges includes a $121 million gain due to ineffectiveness related to gas swaps and collars reflecting a change in the correlation between natural gas and power prices. Pre-tax earnings were also affected by a $3 million loss due to ineffectiveness associated with the Company’s fixed-to-floating interest rate swap which was designated as a hedge of fair value changes in the Company’s Senior Notes.

Note 7 — Long Term Debt

     On May 2, 2007, NRG announced plans for a Comprehensive Capital Allocation Plan to support a fixed and variable structure for the return of capital to stockholders. If fully implemented, this plan will provide the Company with the ability to (i) initiate an annual cash dividend – the fixed component, and (ii) to continue the Company’s historical program of common share repurchases – the variable component.

     Upon completion of the contemplated Comprehensive Capital Allocation Plan:

	•		NRG would become a wholly owned operating subsidiary of a newly created holding company, NRG Holdings, Inc. or Holdco, with the stockholders of NRG becoming stockholders of Holdco;
	•		Holdco would borrow up to $1 billion under a new term loan financing, or Holdco Credit Facility; and
	•		Holdco would make a capital contribution to NRG in the amount of the $1 billion borrowed under the Holdco Credit Facility, less fees and expenses associated with the loan, which will be used to prepay NRG’s existing Term B loan.

     In connection with the Comprehensive Capital Allocation Plan, on June 8, 2007, NRG completed the $4.4 billion refinancing of the Company’s Senior Credit Facility previously announced on May 2, 2007. The transaction resulted in a 0.25% reduction on the spread that the Company pays on its Term B loan and Synthetic Letter of Credit Facility, a $200 million reduction in the Synthetic Letter of Credit Facility to $1.3 billion, and various amendments to provide improved flexibility, efficiency for returning capital to shareholders, asset repowering and investment opportunities. The pricing on the Company’s Term B loan and Synthetic Letter of Credit Facility is also subject to further reductions upon the achievement of certain financial ratios. The refinancing resulted in a charge of approximately $35 million to the Company’s results of operations for the nine months ended September 30, 2007, which was primarily related to the write-off of previously deferred financing costs.

     Other amendments to NRG’s existing Senior Credit Facility include amendments that:

	•		permit the completion of the Holdco structure;
	•		permit the payment of up to $150 million in annual cash dividends on common stock, upon the implementation of the Holdco structure;
	•		exclude payments made on the Holdco Credit Facility, once funded, from being considered restricted payments under the Senior Credit Facility;
	•		modify the existing excess cash flow prepayment mechanism to provide that prepayments are offered to both NRG and Holdco on a pro rata basis and to provide for mandatory annual prepayments; and
	•		provide additional flexibility to NRG with respect to certain covenants governing or restricting the use of excess cash flow, new investments, new indebtedness and permitted liens.

     On August 6, 2007, NRG entered into an agreement with BNP Paribas, or BNP, whereby BNP has agreed to be an issuing bank under the revolver portion of the Company’s Senior Credit Facility. BNP has agreed to issue up to $350 million of letters of credit under the revolver at a rate of 0.25% of the amount issued. NRG will pay BNP a letter of credit issuance fee in the amount of $250 per each letter of credit issued. This increases the amount of unfunded letters of credit the Company can issue under its Revolving Credit Facility to $650 million. In addition, NRG is permitted to issue additional letters of credit of up $350 million under the Senior Credit Facility through other financial institutions.

     Also in connection with the Comprehensive Capital Allocation Plan, the Company executed the Holdco Credit Facility, which is a delayed-draw credit facility providing for the funding of $1 billion in term loan financing to Holdco. For this commitment, NRG will pay the participants a fee from June 8, 2007, until the earlier of the date the facility is drawn upon or the termination date of December 28, 2007. The fee is equal to 0.5% of the facility for the first 180 days and 0.75% thereafter. No balances were outstanding under this credit facility as of September 30, 2007. The formation of the Holdco structure and the drawdown on the Holdco Credit Facility are subject to certain conditions including approval by several regulatory bodies. The Company expects to be able to satisfy these conditions during the fourth quarter 2007.

     With the recent recovery in financial markets and the prices of NRG’s Senior Notes, on November 2, 2007, the Company exercised its right to provide its Senior Note holders with a conditional change of control notice, and related offer to purchase the Company’s Senior Notes at 101% of par, prior to the actual formation of the Holdco structure. Concurrent with this change of control offer, NRG is seeking consent from the same Senior Note holders to waive the change of control in exchange for a 0.125% fee. Under the terms of the Company’s Senior Notes, holders will have thirty calendar days to respond to the change of control offer and consent solicitation.

     Based on the outcome of this change of control offer and consent solicitation, NRG will make a determination of whether to move forward with the Holdco structure prior to the end of 2007. If the Holdco Credit Facility is drawn, the net proceeds will simultaneously be used to pay down a portion of the Company’s Term B loan under its Senior Credit Facility. As a result, the Company’s Senior Notes restricted payments capacity that governs, among other things, the amount of capital that can be returned to shareholders will expand by a similar amount. In addition, NRG will retain the right, but not the obligation, to purchase any or all of the Senior Notes tendered by investors during this process regardless of whether NRG decides to move forward and form the Holdco structure.

     In connection with the transaction, Bank of America has provided the Company with a $4.2 billion senior unsecured debt financing commitment, subject to customary conditions, to fund the tender offers together with a portion of the Company’s cash on hand.

Note 8 — Changes in Capital Structure

     Stock Split

     On April 25, 2007, NRG’s Board of Directors approved a two-for-one stock split of the Company’s outstanding shares of common stock which was effected through a stock dividend. The stock split entitled each stockholder of record at the close of business on May 22, 2007 to receive one additional share for every outstanding share of common stock held. The additional shares resulting from the stock split were distributed by the Company’s transfer agent on May 31, 2007. In connection with the stock split, the Company transferred approximately $1.3 million from Additional Paid-in Capital to Common Stock, representing the par value of additional shares issued. All share amounts for all periods presented have been adjusted to reflect the stock split.

     The following table reflects the changes in NRG’s common stock issued and outstanding for the nine months ended September 30, 2007 and 2006:

		Authorized				Issued				Treasury				Outstanding
Balance as of December 31, 2006			500,000,000				274,248,264				(29,601,162	)			244,647,102
Capital Allocation Program — Phase II during 2007			—				—				(7,006,700	)			(7,006,700	)
Shares issued from LTIP through September 30, 2007			—				952,519				—				952,519
Retirement of shares through September 30, 2007			—				(14,094,962	)			14,094,962				—
Balance as of September 30, 2007			500,000,000				261,105,821				(22,512,900	)			238,592,921
Balance as of December 31, 2005			500,000,000				200,097,352				(38,693,576	)			161,403,776
Shares issued January 2006			—				41,710,114				—				41,710,114
Acquisition of Texas Genco LLC			—				32,119,008				38,693,576				70,812,584
Capital Allocation Program — Phase I during 2006			—				—				(12,226,000	)			(12,226,000	)
Shares issued from LTIP through September 30, 2006			—				134,810				—				134,810
Balance as of September 30, 2006			500,000,000				274,061,284				(12,226,000	)			261,835,284

     Common Stock

     NRG’s authorized common stock consists of 500 million shares of NRG stock. Common stock issued as of September 30, 2007 and 2006 was 261,105,821 and 274,061,284 shares, respectively.

     Treasury Stock

     In 2006, NRG initiated a Capital Allocation Program to be executed in two phases. Phase I, completed in the fourth quarter 2006, resulted in the repurchase of 21,175,400 shares of the Company’s common stock for approximately $500 million. Phase II, also a $500 million share buyback program, began in the fourth quarter 2006 with the repurchase of 8,425,762 shares of NRG common stock for approximately $232 million. NRG completed Phase II in the third quarter 2007, with the repurchase of 1,337,500 shares of the Company’s common stock for approximately $53 million. The Company has thus repurchased 7,006,700 shares of NRG common stock for approximately $268 million for the nine months ended September 30, 2007.

     As part of Phase I of the Capital Allocation Program, NRG, through its unrestricted wholly-owned subsidiaries NRG Common Stock Fund I, or CSF I, and NRG Common Stock Fund II, or CSF II, issued notes and preferred interests to Credit Suisse. The notes and preferred interest with CSF I and CSF II mature in 2008 and 2009, respectively. These notes and preferred interests contain a feature considered an embedded derivative, which requires NRG to pay to Credit Suisse at maturity, either in cash or stock, the excess of NRG’s then current stock price over a Reference Price. This Reference Price is the price of NRG’s stock in excess of a compound annual growth rate, or CAGR, of 20% beyond the volume-weighted average share price of the stock at the time of repurchase. Although this feature is considered a derivative, it is exempt from derivative accounting under the guidance in paragraph 11(a) of SFAS

133, and will be only be recognized upon settlement with a corresponding impact to Additional Paid-In Capital. As of September 30, 2007, based on the Company’s stock price, the redemption value of this embedded derivative was approximately $72 million.

     Retirement of Treasury Stock

     On May 22, 2007, NRG retired 7,047,481 (14,094,962 on a post-stock split basis) shares of treasury stock. These retired shares are now included in the Company’s pool of authorized but unissued shares. The retired stock had a carrying value of approximately $447 million. The Company’s accounting policy upon the formal retirement of treasury stock is to deduct its par value from Common Stock and to reflect any excess of cost over par value as a deduction from Additional Paid-in Capital.

Note 9 — Equity Compensation

     NRG’s compensation plans allow for anti-dilutive adjustments for stock splits, and as such, all share and per share amounts within the tables below reflect the impact of a two-for-one stock split discussed in Note 8, Changes in Capital Structure.

     Non-Qualified Stock Options, or NQSO’s

     The following table summarizes the change in the Company’s outstanding NQSO balance for the nine months ended September 30, 2007:

										Weighted Average
						Weighted Average				Grant-Date
		Shares				Exercise Price				Fair Value Per Share
Outstanding as of December 31, 2006			3,411,072			$	17.59			$	6.70
Granted			784,350				28.63				8.28
Forfeited			(156,805	)			24.25				7.34
Exercised			(291,180	)			15.65				5.88
Outstanding at September 30, 2007			3,747,437				19.77				7.07
Exercisable at September 30, 2007			1,987,917			$	14.06			$	6.45

     Restricted Stock Units, or RSU’s

     The following table shows the change in the outstanding RSU balance during the nine months ended September 30, 2007:

						Weighted Average
						Grant-Date
Non-vested Shares		Shares				Fair Value Per Share
Non-vested as of December 31, 2006			2,277,186			$	15.73
Granted			561,230				38.54
Vested			(1,097,900	)			10.56
Forfeited			(91,250	)			21.46
Outstanding as of September 30, 2007			1,649,266			$	26.64

     Performance Units, or PU’s

     The following table shows the change in the outstanding PU balance during the nine months ended September 30, 2007:

						Weighted Average
						Grant-Date
Non-vested Shares		Shares				Fair Value Per Share
Non-vested as of December 31, 2006			410,664			$	17.24
Granted			189,300				18.10
Forfeited			(56,000	)			16.51
Outstanding as of September 30, 2007			543,964			$	17.66

Note 10 — Earnings Per Share

     Basic earnings per common share is computed by dividing net income less 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. Both basic and diluted earnings per share for all prior periods have been recast to reflect the impact of the Company’s two-for-one stock split as discussed in Note 8, Changes in Capital Structure.

     The reconciliation of basic earnings per common share to diluted earnings per share is shown in the table below:

		Three months ended September 30								Nine months ended September 30
(In millions, except per share data)		2007				2006				2007				2006
Basic earnings per share
Numerator:
Income from continuing operations		$	268			$	371			$	482			$	588
Preferred stock dividends			(13	)			(14	)			(41	)			(38	)
Net income available to common stockholders from continuing operations			255				357				441				550
Discontinued operations, net of income tax expense			—				51				—				63
Net income available to common stockholders		$	255			$	408			$	441			$	613
Denominator:
Weighted average number of common shares outstanding			239.4				272.4				240.5				260.6
Basic earnings per share:
Income from continuing operations		$	1.07			$	1.31			$	1.83			$	2.11
Discontinued operations, net of income tax expense			—				0.19				—				0.24
Net income		$	1.07			$	1.50			$	1.83			$	2.35
Diluted earnings per share
Numerator:
Net income available to common stockholders from continuing operations		$	255			$	357			$	441			$	550
Add preferred stock dividends for dilutive preferred stock			11				11				34				32
Adjusted income from continuing operations			266				368				475				582
Discontinued operations, net of tax			—				51				—				63
Net income available to common stockholders		$	266			$	419			$	475			$	645
Denominator:
Weighted average number of common shares outstanding			239.4				272.4				240.5				260.6
Incremental shares attributable to the issuance of equity compensation (treasury stock method)			3.8				3.0				3.7				2.8
Incremental shares attributable to embedded derivatives of certain financial instruments (if-converted method)			4.6				—				4.9				—
Incremental shares attributable to assumed conversion features of outstanding preferred stock (if-converted method)			37.5				41.6				37.5				39.2
Total dilutive shares			285.3				317.0				286.6				302.6
Diluted earnings per share:
Income from continuing operations		$	0.93			$	1.16			$	1.66			$	1.92
Discontinued operations, net of tax			—				0.16				—				0.21
Net income		$	0.93			$	1.32			$	1.66			$	2.13

     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)		2007				2006				2007				2006
Equity compensation (NQSO’s and PU’s)			—				0.9				0.4				2.1
5.75% convertible preferred stock			—				—				—				2.4
Embedded derivative of 3.625% redeemable perpetual preferred stock			13.2				16.0				13.0				16.0
Embedded derivative of preferred interests and notes issued by CSF I and CSF II			16.7				10.6				16.6				10.6
Total			29.9				27.5				30.0				31.1

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, the 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. All prior period information has been recast to reflect the change in the Company’s segment structure as discussed in Note 17, Segment Reporting, to the Company’s consolidated financial statements in its Form 10-K.

		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			$	52			$	36			$	7			$	—			$	1,786
Depreciation and amortization			113				25				17				1				1				3				1				—				161
Equity in earnings of unconsolidated affiliates			—				—				—				1				18				—				—				—				19
Income/(loss) from continuing operations before income taxes			275				171				18				13				30				4				(96	)			—				415
Net income/(loss)			161				171				17				13				54				4				(152	)			—				268
Total assets			12,308				1,566				996				246				1,135				213				12,774				(10,034	)			19,204

		Wholesale Power Generation
(In millions)										South
Three months ended September 30, 2006		Texas				Northeast				Central				West				International				Thermal				Corporate				Elimination				Total
Operating revenues		$	1,151			$	478			$	171			$	59			$	46			$	38			$	(1	)		$	—			$	1,942
Depreciation and amortization			104				22				17				—				1				3				1				—				148
Equity in earnings of unconsolidated affiliates			—				—				—				3				15				—				(1	)			—				17
Income/(loss) from continuing operations before income taxes			480				152				18				12				27				6				(86	)			—				609
Income from discontinued operations, net of income taxes			—				—				—				—				51				—				—				—				51
Net income/(loss)			445				153				18				13				74				6				(287	)			—				422

		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			$	139			$	122			$	29			$	(15	)		$	4,644
Depreciation and amortization			341				74				51				2				2				9				4				—				483
Equity in earnings of unconsolidated affiliates			—				—				—				(2	)			42				—				—				—				40
Income/(loss) from continuing operations before income taxes			624				319				24				26				77				32				(304	)			(12	)			786
Net income/(loss)			355				319				23				26				88				32				(349	)			(12	)			482

		Wholesale Power Generation
(In millions)										South
Nine months ended September 30, 2006		Texas (a)				Northeast				Central				West (b)				International				Thermal				Corporate				Elimination				Total
Operating revenues		$	2,498			$	1,196			$	437			$	109			$	133			$	114			$	10			$	(18	)		$	4,479
Depreciation and amortization			309				66				51				1				2				9				5				—				443
Equity in earnings of unconsolidated affiliates			—				—				—				2				43				—				1				—				46
Income/(loss) from continuing operations before income taxes			765				335				32				17				80				12				(311	)			(18	)			912
Income from discontinued operations, net of income taxes			—				—				—				—				50				—				13				—				63
Net income/(loss)			719				335				32				19				113				12				(561	)			(18	)			651

Note 12 — Income Taxes

     Income tax expense for the three and nine months ended September 30, 2007 was $147 million and $304 million, respectively, compared to income tax expense of $238 million and $324 million for the three and nine months ended September 30, 2006, respectively. The income tax expense for the three and nine months ended September 30, 2007 includes domestic tax expense of $170 million and $314 million, respectively, and foreign tax benefit of $23 million and $10 million, respectively. The income tax expense for the three and nine months ended September 30, 2006 includes domestic tax expense of $234 million and $307 million, respectively, and foreign tax expense of $4 million and $17 million, respectively.

     A reconciliation of the U.S. statutory rate to NRG’s effective tax rate from continuing operations for the nine months ended September 30, 2007 and 2006 is as follows:

		Nine months ended September 30
(In millions except rate data)		2007				2006
Income from continuing operations before income taxes		$	786			$	912
Tax at 35%			275				319
State taxes			37				47
Valuation allowance			2				2
Disputed claims reserve			—				(29	)
Foreign operations			(9	)			(23	)
Foreign dividends			21				2
Non-deductible interest			7				—
Change in German tax rate			(30	)			—
Permanent differences including subpart F income			1				6
Income tax expense		$	304			$	324
Effective income tax rate			38.7	%			35.5	%

     The effective income tax rate for the nine months ended September 30, 2007 differs from the U.S. 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 U.S. statutory rate including the impact of a law change that reduced the German tax rate. For the nine months ended September 30, 2006, the effective tax rate differs from the U.S. statutory rate of 35% due to settlements paid from a claimant reserve established at bankruptcy as well as earnings in foreign jurisdictions that are taxed at rates lower than the U.S. statutory rate.

     Deferred tax assets and valuation allowance

     Net deferred tax balance — As of September 30, 2007, NRG recorded a net deferred tax liability of $749 million. Due to an assessment of positive and negative evidence, related to 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 $589 million of tax assets, thus a valuation allowance has remained.

     NOL carryforwards — As of September 30, 2007, the Company had generated total domestic pretax book income of $708 million which fully utilized cumulative domestic net operating loss, or NOL, in the amount of $65 million. In addition, as of September 30, 2007, NRG has cumulative foreign NOL carryforwards of $290 million of which $78 million will expire in 2016 and of which $212 million do not have an expiration date.

     Uncertain tax benefits

     NRG has identified certain unrecognized tax benefits whose after-tax value was $712 million, of which $19 million would impact the Company’s effective tax rate if recognized. Of the $712 million in unrecognized tax benefits, $693 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. As of September 30, 2007, NRG has recorded a $51 million non-current tax liability for unrecognized tax benefits. This amount was recorded after utilization in 2007 of the cumulative domestic NOL.

     NRG has accrued interest and penalties related to these unrecognized tax benefits of approximately $4 million as of the adoption of FIN 48 by the Company on January 1, 2007. The Company recognizes interest and penalties related to unrecognized tax benefits in income tax expense. For the three and nine months ended September 30, 2007, 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 U.S. federal jurisdiction and various state and foreign jurisdictions including major operations located in Germany, Australia, and Brazil. The Company is no longer subject to U.S. 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.

     German Tax Reform Act 2008

     On July 6, 2007, the German government passed the Tax Reform Act of 2008, which reduces the German statutory and resulting effective tax rates on earnings from approximately 36% to approximately 27% effective January 1, 2008. Due to this reduction in the statutory and resulting effective tax rate, during the third quarter 2007, NRG recognized a $30 million tax benefit and as of September 30, 2007, NRG had a German net deferred tax liability of approximately $79 million which includes the impact of this tax rate change.

Note 13 — Benefit Plans and Other Postretirement Benefits

     The net annual periodic pension cost for the three and nine months ended September 30, 2007 and 2006 related to all of the Company’s defined benefit pension plans, include the following components:

		Defined Benefit Pension Plans
		Three months ended September 30,								Nine months ended September 30,
(In millions)		2007				2006				2007				2006
Service cost benefits earned		$	3			$	4			$	11			$	13
Interest cost on benefit obligation			4				4				13				12
Expected return on plan assets			(3	)			(2	)			(9	)			(5	)
Net periodic benefit cost		$	4			$	6			$	15			$	20

     The net annual periodic cost for the three and nine months ended September 30, 2007 and 2006 related to all of the Company’s other post retirement benefits plans, include the following components:

		Other Postretirement Benefits Plans
		Three months ended September 30,								Nine months ended September 30,
(In millions)		2007				2006				2007				2006
Service cost benefits earned		$	1			$	1			$	2			$	2
Interest cost on benefit obligation			2				1				4				3
Net periodic benefit cost		$	3			$	2			$	6			$	5