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: March 31, 2008

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)

(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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12 b-2 of the Exchange Act. (Check one):

Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o		Smaller reporting company o
				(Do not check if a smaller reporting company)

     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 April 25, 2008, there were 235,921,977 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 CONDITION AND RESULTS OF OPERATIONS			34
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			58
ITEM 4 — CONTROLS AND PROCEDURES			62
PART II — OTHER INFORMATION			63
ITEM 1 — LEGAL PROCEEDINGS			63
ITEM 1A — RISK FACTORS			63
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			63
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES			63
ITEM 4 — SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS			63
ITEM 5 — OTHER INFORMATION			63
ITEM 6 — EXHIBITS			63
SIGNATURES			65
EX-3.1: CERTIFICATE OF AMENDMENT TO CERTIFICATE OF DESIGNATIONS
EX-10.1: AMENDED AND RESTATED CONTRIBUTION AGREEMENT
EX-10.2: CONTRIBUTION AGREEMENT
EX-10.3: MULTI-UNIT AGREEMENT
EX-10.4: AMENDED AND RESTATED OPERATING AGREEMENT
EX-10.5: AMENDMENT AGREEMENT
EX-10.6: PREFERRED INTEREST AMENDMENT AGREEMENT
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’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, for the year ended December 31, 2007, 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, 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 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 its RepoweringNRG strategy of developing and building new power generation facilities, including new nuclear units, Integrated Gasification Combined Cycle, or IGCC, units and wind 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.

     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
ARO		Asset Retirement Obligation
BACT		Best Available Control Technology
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
CAA		Clean Air Act
CAIR		Clean Air Interstate Rule
CAMR		Clean Air Mercury Rule
Capital Allocation Program		Share repurchase program announced in August 2006
CDWR		California Department of Water Resources
CL&P		Connecticut Light & Power
CO2		Carbon dioxide
COLA		Combined Operating License Application
CSF I		NRG Common Stock Finance I LLC
CSF II		NRG Common Stock Finance II LLC
DPUC		Connecticut Department of Public Utility Control
EFOR		Equivalent Forced Outage Rates — considers the equivalent impact that forced de-ratings have in addition to full forced outages
EPC		Engineering, Procurement and Construction
ERCOT		Electric Reliability Council of Texas, the Independent System Operator and the 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
FCM		Forward Capacity Market
FERC		Federal Energy Regulatory Commission
FIN		FASB Interpretation
FIN46R		FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities”
FSP		FASB Staff Position
GHG		Greenhouse Gases
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
ISO		Independent System Operator, also referred to as Regional Transmission Organization, or RTO
ISO-NE		ISO New England, Inc.
ITISA		Itiquira Energetica S.A.
kW		Kilowatts
kWh		Kilowatt-hours
Letter of Credit Facility		NRG’s $1.3 billion senior secured synthetic letter of credit facility which matures on February 1, 2013
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
MMBtu		Million British Thermal Units
MW		Megawatts
MWh		Saleable megawatt hours net of internal/parasitic load megawatt-hours
NAAQS		National Ambient Air Quality Standard
NEPOOL		New England Power Pool
New York Rest of State		New York State excluding New York City
NiMo		Niagara Mohawk Power Corporation
NINA		Nuclear Innovation North America LLC
NOx		Nitrogen oxide
NOL		Net Operating Loss
NOV		Notice of Violation

		GLOSSARY OF TERMS (cont’d)
NPNS		Normal Purchase Normal Sale
NRC		Nuclear Regulatory Commission
NSR		New Source Review
NYISO		New York Independent System Operator
NYPA		New York Power Authority
OCI		Other Comprehensive Income
Phase II 316(b) Rule		A section of the Clean Water Act regulating cooling water intake structures
PJM		PJM Interconnection LLC
PJM Market		The wholesale and retail electric market operated by PJM primarily in all or parts of Delaware, the District of Columbia, Illinois, Maryland, New Jersey, Ohio, Pennsylvania, Virginia and West Virginia
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
PPA		Power Purchase Agreement
PPM		Parts per Million
PSD		Prevention of Significant Deterioration
Repowering		Technologies utilized to replace, rebuild, or 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 credit facility which matures on February 2, 2011
RGGI		Regional Greenhouse Gas Initiative
RMR		Reliability Must-Run
RPM		Reliability Pricing Model — term for capacity market in PJM market
RTO		Regional Transmission Organization, also referred to as an Independent System Operator, or ISO
Sarbanes-Oxley		Sarbanes-Oxley Act of 2002
SEC		United States Securities and Exchange Commission
Senior Credit Facility		NRG’s senior secured facility, which is comprised of a Term B loan facility which matures on February 1, 2013, a $1.3 billion Letter of Credit Facility, and a $1 billion Revolving Credit Facility, which matures on February 2, 2011
SFAS		Statement of Financial Accounting Standards issued by the FASB
SFAS 71		SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation”
SFAS 109		SFAS No. 109, “Accounting for Income Taxes”
SFAS 133		SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS 141R		SFAS No. 141 (revised 2007), “Business Combinations”
SFAS 157		SFAS No. 157, “Fair Value Measurements”
SFAS 160		SFAS No. 160, “Noncontrolling Interest in Consolidated Financial Statements”
SFAS 161		SFAS No. 161, “Disclosure about Derivative Instruments and Hedging Activities - - an amendment of FASB Statement No. 133”
SO2		Sulfur dioxide
SOP		Statement of Position issued by the American Institute of Certified Public Accountants
STP		South Texas Project — Nuclear generating facility located near Bay City, Texas in which NRG owns a 44% interest
STPNOC		South Texas Project Nuclear Operating Company
Texas Genco		Texas Genco LLC, now referred to as the Company’s Texas region
Tosli		Tosli Acquisition B.V.
US		United States of America
USEPA		United States Environmental Protection Agency
U.S. GAAP		Accounting principles generally accepted in the United States
VAR		Value at Risk
VIE		Variable Interest Entity
WCP		West Coast Power (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
		March 31,
(In millions except per share amounts)		2008				2007
Operating Revenues
Total operating revenues		$	1,302			$	1,299
Operating Costs and Expenses
Cost of operations			804				781
Depreciation and amortization			161				160
General and administrative			75				85
Development costs			12				23
Total operating costs and expenses			1,052				1,049
Gain on sale of assets			—				17
Operating Income			250				267
Other Income/(Expense)
Equity in (losses)/earnings of unconsolidated affiliates			(4	)			13
Other income, net			9				15
Interest expense			(153	)			(179	)
Total other expense			(148	)			(151	)
Income From Continuing Operations Before Income Taxes			102				116
Income tax expense			54				55
Income From Continuing Operations			48				61
Income from discontinued operations, net of income taxes			4				4
Net Income		$	52			$	65
Preferred stock dividends			14				14
Income Available for Common Stockholders		$	38			$	51
Weighted average number of common shares outstanding — basic			236				244
Income from continuing operations per weighted average common share — basic		$	0.14			$	0.19
Income from discontinued operations per weighted average common share — basic			0.02				0.02
Net Income per Weighted Average Common Share — Basic		$	0.16			$	0.21
Weighted average number of common shares outstanding — diluted			245				271
Income from continuing operations per weighted average common share — diluted		$	0.14			$	0.19
Income from discontinued operations per weighted average common share — diluted			0.02				0.01
Net Income per Weighted Average Common Share — Diluted		$	0.16			$	0.20

See notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

		March 31, 2008				December 31, 2007
(in millions, except shares and par value)		(unaudited)
ASSETS
Current Assets
Cash and cash equivalents		$	834			$	1,132
Restricted cash			39				29
Accounts receivable, less allowance for doubtful accounts of $1 and $1			456				482
Inventory			454				451
Derivative instruments valuation			2,389				1,034
Deferred income taxes			325				124
Prepayments and other current assets			408				259
Current assets — discontinued operations			59				51
Total current assets			4,964				3,562
Property, plant and equipment, net of accumulated depreciation of $1,848 and $1,695			11,279				11,320
Other Assets
Equity investments in affiliates			451				425
Notes receivable and capital lease, less current portion			529				491
Goodwill			1,786				1,786
Intangible assets, net of accumulated amortization of $392 and $372			852				873
Nuclear decommissioning trust fund			365				384
Derivative instruments valuation			480				150
Other non-current assets			171				176
Intangible assets held-for-sale			3				14
Non-current assets — discontinued operations			94				93
Total other assets			4,731				4,392
Total Assets		$	20,974			$	19,274
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases		$	130			$	466
Accounts payable			349				384
Derivative instruments valuation			2,644				917
Accrued expenses and other current liabilities			293				473
Current liabilities — discontinued operations			37				37
Total current liabilities			3,453				2,277
Other Liabilities
Long-term debt and capital leases			8,101				7,895
Nuclear decommissioning reserve			311				307
Nuclear decommissioning trust liability			300				326
Deferred income taxes			884				843
Derivative instruments valuation			1,332				759
Out-of-market contracts			550				628
Other non-current liabilities			485				412
Non-current liabilities — discontinued operations			79				76
Total non-current liabilities			12,042				11,246
Total Liabilities			15,495				13,523
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			4,095				4,092
Retained earnings			1,308				1,270
Less treasury stock, at cost — 25,832,200 and 24,550,600 shares			(693	)			(638	)
Accumulated other comprehensive loss			(373	)			(115	)
Total Stockholders’ Equity			5,232				5,504
Total Liabilities and Stockholders’ Equity		$	20,974			$	19,274

See notes to condensed consolidated financial statements.

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

(In millions)
Three months ended March 31,		2008				2007
Cash Flows from Operating Activities
Net income		$	52			$	65
Adjustments to reconcile net income to net cash provided by operating activities
Distributions and equity in (earnings)/loss of unconsolidated affiliates			6				(10	)
Depreciation and amortization			161				160
Amortization of nuclear fuel			15				14
Amortization and write-off of financing costs and debt discount/premiums			8				9
Amortization of intangibles and out-of-market contracts			(66	)			(29	)
Changes in deferred income taxes and liability for unrecognized tax benefits			49				47
Changes in nuclear decommissioning trust liability			9				9
Changes in derivatives			132				90
Changes in collateral deposits supporting energy risk management activities			(150	)			(120	)
Gain on sale of assets			—				(17	)
Gain on sale of emission allowances			(14	)			(5	)
Amortization of unearned equity compensation			7				7
Cash used by changes in other working capital			(149	)			(114	)
Net Cash Provided by Operating Activities			60				106
Cash Flows from Investing Activities
Capital expenditures			(164	)			(107	)
Increase in restricted cash, net			(10	)			(5	)
Decrease in notes receivable			9				9
Purchases of emission allowances			(1	)			(61	)
Proceeds from sale of emission allowances			31				32
Investments in nuclear decommissioning trust fund securities			(144	)			(68	)
Proceeds from sales of nuclear decommissioning trust fund securities			135				59
Proceeds from sale of assets			12				29
Net Cash Used by Investing Activities			(132	)			(112	)
Cash Flows from Financing Activities
Payment of dividends to preferred stockholders			(14	)			(14	)
Payment of financing element of acquired derivatives			(1	)			—
Payment for treasury stock			(55	)			(103	)
Proceeds from issuance of common stock, net of issuance costs			2				—
Payment of deferred debt issuance costs			(2	)			—
Payments for short and long-term debt			(154	)			(19	)
Net Cash Used by Financing Activities			(224	)			(136	)
Change in cash from discontinued operations			(6	)			(5	)
Effect of exchange rate changes on cash and cash equivalents			4				2
Net Decrease in Cash and Cash Equivalents			(298	)			(145	)
Cash and Cash Equivalents at Beginning of Period			1,132				777
Cash and Cash Equivalents at End of Period		$	834			$	632

See notes to condensed consolidated financial statements.

NRG ENERGY, INC.
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 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 Securities and Exchange Commission’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 to the Company’s financial statements in its Annual Report on Form 10-K for the year ended December 31, 2007. 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 March 31, 2008, and the results of operations and cash flows for the three months ended March 31, 2008 and 2007, respectively. Certain prior-year amounts have been reclassified for comparative purposes.

     Stock Split

     In May 2007, NRG completed a two-for-one stock split of the Company’s outstanding shares of common stock, which was effected through a stock dividend. All share and per share amounts presented for the three months ended March 31, 2007 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.

     Investment in Affiliate

     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. A wholly owned subsidiary of NRG is managing the construction, which began in late 2007, and is being conducted by an independent engineering, procurement and construction, or EPC, contractor. The project is scheduled to begin commercial operations during the fourth quarter 2008 at which time an affiliate of BP will manage the operations.

     The project will be funded through a combination of equity contributions from the owners and non-recourse project-level debt. NRG delivered a promissory note to Sherbino of $59 million to support its initial capital contribution, payable no later than December 1, 2008, made an additional contribution of $17 million on April 18, 2008, and expects to provide another $11 million by year-end, bringing its total expected equity contribution to $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 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.

     The Company has determined that Sherbino is a variable interest entity, or VIE, but that the Company is not the primary beneficiary that is required to consolidate Sherbino under FASB Interpretation No. 46(R), Consolidation of Variable Interest Entities, or FIN 46R. Consequently, 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 will be included in NRG’s equity in earnings of Sherbino. NRG’s investment at March 31, 2008, net of its promissory note commitment, is a negative $18 million, which is included in “Equity Investments in Affiliates” on the condensed consolidated balance sheet.

     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 FASB 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 FSP No. FAS 157-2, Effective Date of FASB Statement No. 157, which permitted delayed application of this statement for nonfinancial assets and nonfinancial 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. This statement requires a business entity to report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. An entity may decide whether to elect the fair value option for each eligible item on its election date, subject to certain requirements described in the statement. 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 FSP 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, on January 1, 2008. FSP FIN 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 (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 prospectively to all business combinations for which the acquisition date is on or after the beginning of an entity’s first annual reporting period beginning on or after December 15, 2008. The statement establishes principles and 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. As discussed further in Note 11, SFAS 141R will change the application of fresh start accounting to certain of the Company’s unrecognized 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.

     In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51, Consolidated Financial Statements, or SFAS 160. 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 applied prospectively for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008, except for the presentation and disclosure requirements, which shall 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 March 2008, the FASB issued SFAS No. 161, Disclosures About Derivative Instruments and Hedging Activities, or SFAS 161. SFAS 161 requires entities to provide enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under 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, but does not require, comparative disclosures for earlier periods at initial adoption. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. The enhanced disclosures regarding derivative and hedging instruments required by SFAS 161 are relevant to NRG, but will not have an impact on the Company’s results of operations, financial position, or cash flows.

Note 2 — Comprehensive Loss

     The following table summarizes the components of the Company’s comprehensive loss.

(In millions)
Three months ended March 31,		2008				2007
Net income		$	52			$	65
Changes in derivative activity, net of tax			(302	)			(283	)
Foreign currency translation adjustment, net of tax			42				10
Unrealized gain on available-for-sale securities, net of tax			2				—
Other comprehensive loss, net of tax			(258	)			(273	)
Comprehensive loss		$	(206	)		$	(208	)

     The following table summarizes the changes in the Company’s accumulated other comprehensive loss.

(In millions)
As of March 31,		2008
Accumulated other comprehensive loss as of December 31, 2007		$	(115	)
Changes in derivative activity, net of tax			(302	)
Foreign currency translation adjustments, net of tax			42
Unrealized gain on available-for-sale securities, net of tax			2
Accumulated other comprehensive loss as of March 31, 2008		$	(373	)

Note 3 — Discontinued Operations

     The assets and liabilities reported in the balance sheet as discontinued operations represent those of Itiquira Energetica S.A., or ITISA. On December 18, 2007, NRG entered into a sale and purchase agreement to sell its 100% interest in Tosli Acquisition B.V., or Tosli, which holds all NRG’s interest in ITISA, to Brookfield Power Inc., a wholly-owned subsidiary of Brookfield Asset Management Inc. On April 28, 2008, NRG completed the sale and received $288 million in cash proceeds. The sale process will remove approximately $153 million of assets, including $53 million of cash, and approximately $116 million of liabilities, including $61 million of debt, that are classified as discontinued assets and liabilities on the condensed consolidated balance sheet as of March 31, 2008. NRG expects to recognize a pre-tax gain of approximately $250 million and net pre-tax cash additions of approximately $234 million, subject to a purchase price adjustment to be finalized within 90 days of the sale date.

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

(In millions)
Three months ended March 31,		2008				2007
Operating revenues		$	15			$	11
Pre-tax income			7				5
Income from discontinued operations, net of income taxes			4				4

Note 4 — Fair Value of Financial Instruments

     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 asset or liabilities that the Company has the ability to access as of the measurement date. Financial assets and liabilities utilizing Level 1 inputs include active exchange-traded securities and exchange-based derivatives.
	•		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. Financial assets and liabilities utilizing Level 2 inputs include fixed income securities, non-exchange-based derivatives, mutual funds and fair-value hedges.
	•		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. 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.

     The following table presents assets and liabilities measured and recorded at fair value on the Company’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy during the three months ended March 31, 2008:

(In millions)		Fair Value
As of March 31, 2008		Level 1				Level 2				Level 3				Total
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities		$	—			$	—			$	30			$	30
Marketable equity securities			10				—				—				10
Trust fund investments			216				131				25				372
Derivative assets			510				2,303				56				2,869
Total assets		$	736			$	2,434			$	111			$	3,281
Derivative liabilities		$	566			$	3,363			$	47			$	3,976

     The following table reconciles, for the period ended March 31, 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
Three months ended March 31, 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			(2	)			—				(35	)			(37	)
Included in nuclear decommissioning obligations			—				(2	)			—				(2	)
Included in other comprehensive income			—				—				10				10
Purchases/(sales)			—				(9	)			(11	)			(20	)
Transfer in/(out) of Level 3			—				(1	)			18				17
Ending balance as of March 31, 2008		$	30			$	25			$	9			$	64
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 March 31, 2008		$	(2	)		$	—			$	(28	)		$	(30	)

     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 derivatives are recorded in operating revenues.

     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 discounted cash flow methodology which utilizes significant assumptions that are unobservable.

     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, U.S. 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 U.S. 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.

     Derivative fair value measurements

     The majority of NRG’s energy related 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. 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. The terms for which such price information is available vary by commodity, region and product. The remainder of the assets represent contracts for which external valuations are not available, primarily option contracts. These contracts are valued using the Black Scholes model, an industry standard option valuation model. The fair values in each category reflect the level of forward prices and volatility factors as of March 31, 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.

     Credit Risk Associated with Derivative Instruments

     NRG would be exposed to credit-related losses in the event of non-performance by counterparties that enter into derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of the contracts as of the reporting date. For energy-related derivative instruments, NRG attempts to enter into enabling agreements that allow for payment netting with its counterparties, which reduces NRG’s exposure to counterparty credit risk by providing for the offset of amounts payable against amounts receivable to or from the counterparty. Each enabling agreement is commodity specific and so netting is limited to transactions involving that specific commodity except where master netting agreements exist that allow for cross commodity netting. In addition to payment netting language, the credit risk group establishes credit limits and collateral requirements for a counterparty as defined in the enabling agreements. Counterparty credit limits are based on an internal credit assessment that considers a variety of quantitative and qualitative factors, including but not limited to the financial health of the counterparty, credit ratings and risk management capabilities. To the extent that a credit limit is exceeded by the counterparty, NRG will require the counterparty to post collateral as specified in the enabling agreement. NRG’s credit risk group monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and portfolio basis.

     Under the guidance of FSP FIN 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 March 31, 2008, the Company has the right to reclaim $241 million of cash collateral paid and the obligation to return $20 million of cash collateral received. These amounts are included in other current assets and liabilities, respectively.

Note 5 — 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, 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 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 hedge 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	)

(In millions)		Energy				Interest
Three months ended March 31, 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			(17	)			—				(17	)
Mark-to-market of hedge contracts			(259	)			(7	)			(266	)
Accumulated OCI balance at March 31, 2007		$	(83	)		$	9			$	(74	)

     As of March 31, 2008 and 2007, the net balances in OCI relating to SFAS 133 were unrecognized losses of approximately $567 million and $74 million, which were net of $371 million and $50 million, respectively, in income taxes.

     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 tables summarizes the pre-tax effects of non-hedge derivatives, derivatives that do not qualify as hedges, and ineffectiveness of hedge derivatives on NRG’s statement of operations:

		Three months ended March 31,
(In millions)		2008				2007
Revenue from operations — energy commodities		$	(141	)		$	(90	)
Interest expense — interest rate swaps			—				—
Total impact to statement of operations		$	(141	)		$	(90	)

     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 is 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. In addition, the Company recorded $16 million of gains associated with open positions also related to trading activity.

     For the three months ended March 31, 2007, the unrealized loss associated with changes in the fair value of derivative instruments not accounted for as hedge derivatives of $90 million is comprised of $79 million of fair value decreases in forward sales of electricity and fuel, a $44 million gain due to the ineffectiveness associated with financial forward contracted electric and gas sales, $70 million from the reversal of mark-to-market gains which ultimately settled as financial revenues of which $57 million was related to economic

hedges and $13 million was related to trading activity. In addition, the Company recorded $15 million of gains associated with open positions also related to trading activity.

Note 6 — Long Term Debt

     Debt Related to Capital Allocation Program

     In March 2008, the Company executed an arrangement with Credit Suisse 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 for any 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 is $248 million.

     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 7 — 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, 2008 and 2007:

		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			—								(1,281,600	)			(1,281,600	)
Shares issued from LTIP through March 31, 2008			—				93,251								93,251
Balance as of March 31, 2008			500,000,000				261,378,780				(25,832,200	)			235,546,580
Balance as of December 31, 2006			500,000,000				274,248,264				(29,601,162	)			244,647,102
Capital Allocation Program — Phase II			—				—				(3,000,000	)			(3,000,000	)
Shares issued from LTIP through March 31, 2007			—				598,914				—				598,914
Balance as of March 31, 2007			500,000,000				274,847,178				(32,601,162	)			242,246,016

     Common Stock

     NRG’s authorized shares of common stock consist of 500 million shares. Common stock issued as of March 31, 2008 and 2007 was 261,378,780 and 274,847,178 shares, respectively.

     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. This was followed in January 2008 with the repurchase of an additional 344,000 shares of NRG common stock for approximately $15 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 March 2008, the Company repurchased an additional 937,600 shares of NRG common stock in the open market for approximately $40 million. As of March 31, 2008, NRG had repurchased a total of 3,319,300 shares of NRG common stock at a cost of approximately $140 million as part of its 2008 Capital Allocation Program.

Note 8 — Equity Compensation

     Non-Qualified Stock Options, or NQSO’s

     The following table summarizes the Company’s NQSO activity as of March 31, 2008 and the changes during the three months then ended:

						Weighted				Aggregate Intrinsic
						Average				Value
		Shares				Exercise Price				(In millions)
Outstanding as of December 31, 2007			3,579,775			$	19.98
Granted			929,500				42.63
Forfeited			(20,667	)			34.11
Exercised			(73,204	)			23.42
Outstanding at March 31, 2008			4,415,404				24.62			$	63
Exercisable at March 31, 2008			2,413,256			$	16.87				53

     The weighted average grant date fair value of NQSO’s granted for the three months ending March 31, 2008 was $11.08.

     Restricted Stock Units, or RSU’s

     The following table summarizes the Company’s non-vested RSU awards as of March 31, 2008 and changes during the three months then ended:

						Weighted Average Grant-
						Date
Non-vested Shares		Shares				Fair Value Per Unit
Non-vested as of December 31, 2007			1,588,316			$	26.99
Granted			136,000				41.66
Vested			(16,400	)			18.26
Forfeited			(16,790	)			31.09
Non-vested as of March 31, 2008			1,691,126			$	28.21

     Performance Units, or PU’s

     The following table summarizes the Company’s non-vested PU awards as of March 31, 2008 and changes during the three months then ended:

						Weighted Average
						Grant- Date
Non-vested Shares		Shares				Fair Value Per Unit
Non-vested as of December 31, 2007			536,764			$	20.18
Granted			179,900				28.90
Forfeited			(8,000	)			21.25
Non-vested as of March 31, 2008			708,664			$	22.38

Note 9 — 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.

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

		Three months ended March 31,
(In millions, except per share data)		2008				2007
Basic earnings per share
Numerator:
Income from continuing operations		$	48			$	61
Preferred stock dividends			(14	)			(14	)
Net income available to common stockholders from continuing operations			34				47
Discontinued operations, net of income tax expense			4				4
Net income available to common stockholders		$	38			$	51
Denominator:
Weighted average number of common shares outstanding			236.3				244.0
Basic earnings per share:
Income from continuing operations		$	0.14			$	0.19
Discontinued operations, net of income tax expense			0.02				0.02
Net income		$	0.16			$	0.21
Diluted earnings per share
Numerator:
Net income available to common stockholders from continuing operations		$	34			$	47
Add preferred stock dividends for dilutive preferred stock			—				4
Adjusted income from continuing operations			34				51
Discontinued operations, net of tax			4				4
Net income available to common stockholders		$	38			$	55
Denominator:
Weighted average number of common shares outstanding			236.3				244.0
Incremental shares attributable to the issuance of equity compensation (treasury stock method)			3.7				3.2
Incremental shares attributable to embedded derivatives of certain financial instruments (if-converted method)			5.3				2.3
Incremental shares attributable to assumed conversion features of outstanding preferred stock (if-converted method)			—				21.0
Total dilutive shares			245.3				270.5
Diluted earnings per share:
Income from continuing operations		$	0.14			$	0.19
Income from discontinued operations, net of tax			0.02				0.01
Net income		$	0.16			$	0.20

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)		2008				2007
Equity compensation (NQSO’s and PU’s)			1.3				1.0
4.0% convertible preferred stock			21.0				—
5.75% convertible preferred stock			16.5				16.5
Embedded derivative of 3.625% redeemable perpetual preferred stock			12.2				14.5
Embedded derivative of preferred interests and notes issued by CSF I and CSF II			16.8				17.6
Total			67.8				49.6

Note 10 — 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 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				(104	)			—				102
Income from discontinued operations, net of income taxes			—				—				—				—				4				—				—				—				4
Net income/(loss)		$	37			$	59			$	39			$	12			$	24			$	5			$	(124	)		$	—			$	52
Total assets		$	12,072			$	1,550			$	972			$	255			$	1,276			$	214			$	14,447			$	(9,812	)		$	20,974

		Wholesale Power Generation
(In millions)										South
Three months ended March 31, 2007		Texas				Northeast				Central				West				International				Thermal				Corporate				Elimination				Total
Operating revenues		$	695			$	342			$	150			$	28			$	32			$	49			$	5			$	(2	)		$	1,299
Depreciation and amortization			114				25				17				—				—				3				1				—				160
Equity in (losses)/earnings of unconsolidated affiliates			—				—				—				(2	)			15				—				—				—				13
Income/(loss) from continuing operations before income taxes			113				38				10				5				19				23				(92	)			—				116
Income from discontinued operations, net of income taxes			—				—				—				—				4				—				—				—				4
Net income/(loss)		$	60			$	38			$	10			$	5			$	17			$	23			$	(88	)		$	—			$	65

Note 11 — Income Taxes

     Income tax expense from continuing operations for the three months ended March 31, 2008 and March 31, 2007 was $54 million and $55 million, respectively. The income tax expense for the three months ended March 31, 2008 included domestic tax expense of $50 million and foreign tax expense of $4 million. The income tax expense for the three months ended March 31, 2007 included domestic tax expense of $48 million and foreign tax expense of $7 million.

     A reconciliation of the U.S. statutory rate to NRG’s effective tax rate from continuing operations is as follows:

(In millions except rate data)
Three months ended March 31,		2008				2007
Income from continuing operations before income taxes		$	102			$	116
Tax at 35%			36				41
State taxes			6				6
Valuation allowance			8				—
Foreign operations			(3	)			(1	)
Foreign dividend			6				5
Non-deductible interest			3				3
Other permanent differences including subpart F income			(2	)			1
Income tax expense		$	54			$	55
Effective income tax rate			52.9	%			47.4	%

     The effective income tax rate for the three months ended March 31, 2008 and 2007 differs from the U.S. statutory rate of 35% due to an establishment of valuation allowance, 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.

     Deferred tax assets and valuation allowance

     Net deferred tax balance — As of March 31, 2008, NRG recorded a net deferred tax asset of $3 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 $562 million of tax assets, thus a valuation allowance has remained, resulting in a net deferred tax liability of $559 million.

     NOL carryforwards — As of March 31, 2008, the Company has cumulative foreign NOL carryforwards of $305 million of which $75 million will expire starting in 2011 through 2017 and of which $230 million do not have an expiration date.

     Valuation Allowance — As of March 31, 2008, the Company’s valuation allowance was increased by approximately $9 million of federal and $1 million of state tax as a result of net capital losses generated during the period. The Company reduced its foreign valuation allowance by $1 million due to the utilization of foreign NOL.

     Uncertain tax benefits

     NRG has identified certain unrecognized tax benefits whose after-tax value was $698 million, of which $25 million would impact the Company’s effective tax rate if recognized. Of the $698 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. As of March 31, 2008, NRG has recorded a $50 million non-current tax liability for unrecognized tax benefits. 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.

     NRG has accrued interest and penalties related to these unrecognized tax benefits of approximately $3 million as of March 31, 2008. The Company recognizes interest and penalties related to unrecognized tax benefits in income tax expense. For the quarter ended March 31, 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 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.

     The Company has been contacted for examination by the Internal Revenue Service for years 2004 through 2006. The audit is expected to commence in June 2008 and continue for approximately 18 to 24 months.

Note 12 — 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, 2008 was $13 million.

     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		2008				2007
Service cost benefits earned		$	4			$	4
Interest cost on benefit obligation			5				4
Expected return on plan assets			(4	)			(3	)
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		2008				2007
Service cost benefits earned		$	1			$	1
Interest cost on benefit obligation			1				1
Net periodic benefit cost		$	2			$	2

   STP Defined Benefit Plans

     NRG has a 44% undivided ownership interest in South Texas Project, or STP. 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 Company has also recognized net periodic costs related to its 44% interest in STP defined benefits plans of $2 million for both the three months ended March 31, 2008 and 2007.

Note 13 — 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 three months ended March 31, 2008 with total commitments of approximately $213 million, spanning over 2008 and 2009. In addition, NRG natural gas purchase commitments increased by $122 million over the next three years due to higher forward prices.

     First and Second Lien Structure

     NRG has granted first and second priority liens to certain counterparties on substantially all of the Company’s assets in the United States in order to secure certain obligations, which are primarily long-term in nature under certain power 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 these agreements. 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.

     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 current 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 some second lien holders 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.

     On March 31, 2008, the Company moved a second lien counterparty to a first lien position, resulting in the release of approximately $57 million of letters of credit. As of March 31, 2008, and April 25, 2008, the net discounted exposure less collateral posted on the agreements and hedges that were subject to the first lien structure were approximately $1.1 billion and $1.6 billion, respectively. As of March 31, 2008, and April 25, 2008, the net discounted exposure less collateral posted on the agreements and hedges that were subject to the second lien structure were approximately $382 million and $579 million, respectively.

     RepoweringNRG

     NRG has made non-refundable deposits relating to RepoweringNRG projects totaling approximately $118 million primarily towards the procurement of wind turbines. The Company believes that these deposits are necessary for the timely and successful execution of these projects. The deposits are in support of expected deliveries of wind turbines and other equipment totaling approximately $417 million through 2009. In addition, as discussed in Note 1, NRG expects to contribute approximately $87 million in equity to Sherbino in 2008 and has posted a letter of credit in that amount.

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. 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 from its currently recorded reserves and that such difference 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 effect NRG’s consolidated financial position, results of operations, or cash flows.

     California Department of Water Resources

     On December 19, 2006, the U.S. 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 power contracts and remanded the case to FERC for further proceedings consistent with the decision. One of these contracts was the wholesale power contract between the California Department of Water Resources, or CDWR, and subsidiaries of WCP. This 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. For WCP, the alleged overcharges totaled approximately $940 million for 2001 and 2002. The complaint demanded that FERC abrogate the CDWR contract and sought refunds associated with revenues collected under the contract. In 2003, FERC rejected this complaint, denied rehearing, and the case was appealed to the Ninth Circuit where oral argument was held on December 8, 2004. On December 19, 2006, the Court decided that in FERC’s review of the contracts at issue, FERC could not rely on the Mobile-Sierra standard presumption of just and reasonable rates, where such contracts were not reviewed by 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 review by the U.S. Supreme Court and on September 25, 2007, the Court agreed to hear two of the filed petitions. Although WCP’s petition was not selected for review, the Court’s ultimate decision with respect to the other defendants’ petitions will apply equally to WCP. Oral argument occurred on February 19, 2008, and a decision is expected from the Court by the end of the third quarter 2008. 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 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.

     Station Service Disputes

     On October 2, 2000, Niagara Mohawk Power Corporation, or NiMo, commenced an action against NRG in New York state court seeking damages related to NRG’s alleged failure to pay retail tariff amounts for utility services at the Dunkirk plant between June 1999 and September 2000. The parties agreed to consolidate this action with two other actions against the Huntley and Oswego plants. On October 8, 2002, by stipulation and order, this action was stayed pending submission to FERC of 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 U.S. 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 U.S. 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 an order finding that, at times when NRG is not able to self-supply its station power needs, there is a sale of station power from a third-party and retail charges apply. In August 2003, the parties agreed to submit the dispute to binding arbitration. 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. A component of the settlement that requires action from ISO-NE is pending.

     Native Village of Kivalina and City of Kivalina

     Twenty-four electric generating companies and oil and gas companies have been named as defendants in this complaint, which has been filed but not yet served on NRG. Damages of up to $400 million have been asserted. The complaint alleges that the carbon dioxide emissions of defendants contribute to global climate changes which has harmed the plaintiffs. The complaint was filed on behalf of a small Alaskan town and seeks damages associated with those tribes having to relocate from the northern coast of Alaska, purportedly because of the effects of global warming. By agreement with the plaintiffs, the response date for all defendants to the complaint is June 30, 2008.

     Spring Creek Coal Company

     In August 2007, Spring Creek Coal Company filed a complaint against NRG Texas LP, NRG South Texas LP, NRG Texas Power LLC, NRG Texas LLC, and NRG Energy, Inc. in the U.S. District Court for the federal district of Wyoming. The complaint alleged multiple breaches in 2007 of a 1978 coal supply agreement as amended by a later 1987 agreement, which plaintiff alleges is a “take or pay” contract. Several dispositive motions were set to be heard by the court on July 11, 2008, with a trial scheduled to begin on September 8, 2008. On April 10, 2008, the parties reached a settlement in principal ending the litigation. A settlement agreement is expected to be executed in the second quarter of 2008. The settlement provides that while neither party admits liability, NRG will pay 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 contract in the future will be reduced by an identical amount. In addition, NRG will receive a price reduction on all remaining tons of the coal supply agreement, valued at approximately $3 million. NRG recorded a $15 million reserve as of March 31, 2008.

     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.

     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 April 25, 2008, the reserve held approximately $10 million in cash and approximately 1,319,142 shares of common stock on a post-stock split basis. NRG believes the cash and stock together represent sufficient funds to satisfy all remaining disputed claims.

Note 14 — 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 — 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.

     On March 18, 2008, the U.S. Court of Appeals for the D.C. Circuit rejected the appeal filed by the Attorneys General of the State of Connecticut and Commonwealth of Massachusetts regarding 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 that is in the process of being implemented 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 court, although one procedural argument relating to future challenges by non-settling parties was sustained.

     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 has sought rehearing on the refund issue, thus resolving the contingency. NRG, as well as other market participants, have sought rehearing of other aspects of the March 7 order.

     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 reporting. This audit may result in the resettlement of NRG’s capacity revenues from the Astoria facility due to a redetermination of the amount of available capacity. NRG is currently in settlement discussions with the NYISO, and the Company believes that it is adequately reserved.

     PJM — On August 23, 2007, several entities, 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 appeals of the FERC orders accepting the settlement of the locational capacity 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. 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.

     On January 15, 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 is also seeking an investigation of periods prior to the complaint that could lead to disgorgement by certain entities, and possibly a resettlement of the market back to September 8, 2006. The principal impacts on NRG would occur as a resettlement of the LMPs, which is not viewed as likely at this time, and going-forward in the form of lower LMPs. In addition, NRG’s peaking units at its energy center in Dover, Delaware were built in 2001 and utilize the post-1999 bidding exemption.

Note 15 — Environmental Matters

     The construction and operation of power projects are subject to stringent environmental and safety protection and land use laws and regulation in the U.S. If such laws and regulations become more stringent, or new laws, interpretations or compliance policies apply and NRG’s facilities are not exempt from coverage, the Company could be required to make modifications to further reduce potential environmental impacts. New greenhouse gas legislation and regulations to mitigate the effects of gases, 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 through 2012 to meet NRG’s environmental commitments will be between $1.0 billion and $1.4 billion. These capital expenditures, in general, are related to installation of particulate, SO₂, NO_x, and mercury controls to comply with Clean Air Interstate Rule, or CAIR, consent orders and state requirements as well as installation of Best Technology Available under the Phase II 316(b) rule. NRG continues to explore cost effective alternatives that can achieve desired results. The range reflects alternative strategies available with respect to the Company’s Indian River plant.

     The legal challenges to both the CAIR and CAMR regulations may alter the composition and rate of spending for environmental retrofits at our facilities until the regulations becomes more certain. This may be most felt in states such as Texas and Louisiana which adopted the federal CAMR rather than a state implementation plan. The full impact of these legal challenges on the scope and timing of environmental retrofits cannot be determined at this time.

     South Central Region

     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 16 — 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, operation and maintenance agreements, service agreements, settlement agreements, and other types of contractual agreements with vendors and other third parties. 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 on Form 10-K for the year ended December 31, 2007.

     For the three months ended March 31, 2008, NRG had net increases to its guarantee obligations under other commercial arrangements of approximately $178 million. These pertain to payment obligations of NRG Power Marketing LLC, or PMI.

Note 17 — Condensed Consolidating Financial Information

     As of March 31, 2008, 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 March 31, 2008:

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.
NRG Affiliate Services, Inc.		Texas Genco GP LLC
NRG Arthur Kill Operations, Inc.		Texas Genco Holdings, Inc.
NRG Asia-Pacific, Ltd.		Texas Genco LP LLC
NRG Astoria Gas Turbine Operations, Inc.		Texas Genco Operating Services LLC
NRG Bayou Cove LLC		Texas Genco Services LP
NRG Cabrillo Power Operations, Inc.		Vienna Operations, Inc.
NRG Cadillac Operations Inc.		Vienna Power LLC
NRG California Peaker Operations LLC		WCP (Generation) Holdings LLC
NRG Cedar Bayou Development Company LLC		West Coast Power LLC
NRG Connecticut Affiliate Services, Inc.

     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 with Rule 3-10 under the Securities and Exchange Commission’s Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiaries or non-guarantor subsidiaries operated as independent entities.

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

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

										NRG Energy,
		Guarantor				Non-Guarantor				Inc.								Consolidated
(In millions)		Subsidiaries				Subsidiaries				(Note Issuer)				Eliminations(a)				Balance
Operating Revenues
Total operating revenues		$	1,200			$	102			$	—			$	—			$	1,302
Operating Costs and Expenses
Cost of operations			735				67				2				—				804
Depreciation and amortization			153				6				2				—				161
General and administrative			12				4				59				—				75
Development costs			—				2				10				—				12
Total operating costs and expenses			900				79				73				—				1,052
Operating Income/(Loss)			300				23				(73	)			—				250
Other Income/(Expense)
Equity in earnings/(losses) of consolidated subsidiaries			72				(18	)			145				(199	)			—
Equity in losses of unconsolidated affiliates			(2	)			(2	)			—				—				(4	)
Other income, net			1				3				5				—				9
Interest expense			(51	)			(18	)			(84	)			—				(153	)
Total other income/(expense)			20				(35	)			66				(199	)			(148	)
Income From Continuing Operations Before Income Taxes			320				(12	)			(7	)			(199	)			102
Income tax expense/(benefit)			121				(8	)			(59	)			—				54
Income From Continuing Operations			199				(4	)			52				(199	)			48
Income from discontinued operations, net of income taxes			—				4				—				—				4
Net Income		$	199			$	—			$	52			$	(199	)		$	52

(a)

All significant intercompany transactions have been eliminated in consolidation.

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
March 31, 2008

		Guarantor				Non-Guarantor				NRG Energy, Inc.								Consolidated
(In millions)		Subsidiaries				Subsidiaries				(Note Issuer)				Eliminations(a)				Balance
ASSETS
Current Assets
Cash and cash equivalents		$	—			$	175			$	698			$	—			$	873
Accounts receivable, net			418				38				—				—				456
Inventory			441				13				—				—				454
Derivative instruments valuation			2,389				—				—				—				2,389
Deferred income taxes			354				(23	)			(6	)			—				325
Prepayments and other current assets			323				41				206				(162	)			408
Current assets — discontinued operations							59												59
Total current assets			3,925				303				898				(162	)			4,964
Net property, plant and equipment			10,757				499				23				—				11,279
Other Assets
Investment in subsidiaries			685				(18	)			9,484				(10,151	)			—
Equity investments in affiliates			26				425				—				—				451
Notes receivable and capital lease			387				529				3,751				(4,138	)			529
Goodwill			1,786				—				—				—				1,786
Intangible assets, net			837				15				—				—				852
Nuclear decommissioning trust			365				—				—				—				365
Derivative instruments valuation			473				—				7				—				480
Other non-current assets			9				1				161				—				171
Intangible assets held-for-sale			3				—				—				—				3
Non-current assets — discontinued operations			—				94				—				—				94
Total other assets			4,571				1,046				13,403				(14,289	)			4,731
Total Assets		$	19,253			$	1,848			$	14,324			$	(14,451	)		$	20,974
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt		$	83			$	99			$	31			$	(83	)		$	130
Accounts payable			(432	)			417				364				—				349
Derivative instruments valuation			2,640				—				4				—				2,644
Accrued expenses and other current liabilities			175				43				154				(79	)			293
Current liabilities — discontinued operations			—				37				—				—				37
Total current liabilities			2,466				596				553				(162	)			3,453
Other Liabilities
Long-term debt			3,671				838				7,730				(4,138	)			8,101
Nuclear decommissioning reserve			311				—				—				—				311
Nuclear decommissioning trust liability			300				—				—				—				300
Deferred income taxes			638				(153	)			399				—				884
Derivative instruments valuation			1,201				28				103				—				1,332
Out-of-market contracts			550				—				—				—				550
Other long-term obligations			373				52				60				—				485
Non-current liabilities — discontinued operations			—				79				—				—				79
Total non-current liabilities			7,044				844				8,292				(4,138	)			12,042
Total liabilities			9,510				1,440				8,845				(4,300	)			15,495
3.625% Preferred Stock			—				—				247				—				247
Stockholders’ Equity			9,743				408				5,232				(10,151	)			5,232
Total Liabilities and Stockholders’ Equity		$	19,253			$	1,848			$	14,324			$	(14,451	)		$	20,974