Edgar Filing: NRG ENERGY, INC.

Large accelerated filer þ

Accelerated filer o

Non-accelerated filer o

Smaller reporting company o

(Do not check if a smaller reporting company)

10-Q

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, 2009

Commission File Number: 001-15891

NRG Energy, Inc.

(Exact name of Registrant as specified in its charter)


Delaware		41-1724239
(State or other jurisdiction		(I.R.S. Employer
of incorporation or organization)		Identification No.)

211 Carnegie Center Princeton, New Jersey		08540
(Address of principal executive offices)		(Zip Code)

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

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.

Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes o No o

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):

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

Yes o No þ

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.

Yes þ No o

As of April 28, 2009, there were 265,272,685 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		8
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES		8
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		42
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		68
ITEM 4 — CONTROLS AND PROCEDURES		72
PART II — OTHER INFORMATION		73
ITEM 1 — LEGAL PROCEEDINGS		73
ITEM 1A — RISK FACTORS		73
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		73
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES		73
ITEM 4 — SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS		73
ITEM 5 — OTHER INFORMATION		73
ITEM 6 — EXHIBITS		74
SIGNATURES		75
EX-10.1
EX-31.1
EX-31.2
EX-31.3
EX-32

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, 2008, including the following:

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

	•		Hazards customary to the power production industry and power generation operations such as fuel and electricity price volatility, unusual weather conditions, catastrophic weather-related or other damage to facilities, unscheduled generation outages, maintenance or repairs, unanticipated changes to fuel supply costs or availability due to higher demand, shortages, transportation problems or other developments, environmental incidents, or electric transmission or gas pipeline system constraints and the possibility that NRG may not have adequate insurance to cover losses as a result of such hazards;

	•		The effectiveness of NRG’s risk management policies and procedures, and the ability of NRG’s counterparties to satisfy their financial commitments;

	•		Counterparties’ collateral demands and other factors affecting NRG’s liquidity position and financial condition;

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

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

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

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

	•		Price mitigation strategies and other market structures employed by ISOs 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, wind and solar projects;

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

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

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

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

Forward-looking statements speak only as of the date they were made, and NRG undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors that could cause NRG’s actual results to differ materially from those contemplated in any forward-looking statements included in this Quarterly Report 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:


APB		Accounting Principles Board
APB 18		APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock”
Baseload capacity		Electric power generation capacity normally expected to serve loads on an around-the-clock basis throughout the calendar year
BTA		Best Technology Available
BTU		British Thermal Unit
CAA		Clean Air Act
CAGR		Compound annual growth rate
CAIR		Clean Air Interstate Rule
CAISO		California Independent System Operator
Capital Allocation Plan		Share repurchase program
Capital Allocation Program		NRG’s plan of allocating capital between debt reduction, reinvestment in the business, and share repurchases through the Capital Allocation Plan
CDWR		California Department of Water Resources
CL&P		The Connecticut Light & Power Company
CO₂		Carbon dioxide
CS		Credit Suisse Group
CSF I		NRG Common Stock Finance I LLC
CSF II		NRG Common Stock Finance II LLC
CSRA		Credit sleeve facility with Merrill Lynch in connection with acquisition of Reliant Retail, as hereinafter defined
DNREC		Delaware Department of Natural Resources and Environmental Control
DPUC		Department of Public Utility Control
EAF		Annual Equivalent Availability Factor, which measures the percentage of maximum generation available over time as the fraction of net maximum generation that could be provided over a defined period of time after all types of outages and deratings, including seasonal deratings, are taken into account
EFOR		Equivalent Forced Outage Rates — considers the equivalent impact that forced de-ratings have in addition to full forced outages
EITF		Emerging Issues Task Force
EITF 07-5		EITF No. 07-5, “Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock”
EITF 08-5		EITF 08-5, “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement”
EITF 08-6		EITF 08-6, “Equity Method Investment Accounting Considerations”
EPC		Engineering, Procurement and Construction
ERCOT		Electric Reliability Council of Texas, the Independent System Operator and the Regional Reliability Coordinator of the various electricity systems within Texas
ESPP		Employee Stock Purchase Plan
Exchange Act		The Securities Exchange Act of 1934, as amended
Expected Baseload Generation		The net baseload generation limited by economic factors (relationship between cost of generation and market price) and reliability factors (scheduled and unplanned outages)
FASB		Financial Accounting Standards Board — the designated organization for establishing standards for financial accounting and reporting
FCM		Forward Capacity Market
FERC		Federal Energy Regulatory Commission
FIN		FASB Interpretation
FIN 18		FIN No. 18, “Accounting for Income Taxes in Interim Periods”
FIN 48		FIN No. 48, “Accounting for Uncertainty in Income Taxes”
FPA		Federal Power Act
Fresh Start		Reporting requirements as defined by SOP 90-7
FSP		FASB Staff Position
FSP APB 14-1		FSP No. APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement)”
FSP FAS 107-1 and APB 28-1		FSP No. FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments”
FSP FAS 132R-1		FSP No. FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets”


		GLOSSARY OF TERMS (continued)

FSP FAS 141R-1		FSP No. FAS 141(R)-1 “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies”
FSP FAS 142-3		FSP No. FAS 142-3, “Determination of the Useful Life of Intangible Asset”
FSP FAS 157-3		FSP No. FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active”
FSP FAS 157-4		FSP No. FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly”
GHG		Greenhouse Gases
Gross Generation		The total amount of electric energy produced by generating units and measured at the generating terminal in kWh’s or MWh’s
Heat Rate		A measure of thermal efficiency computed by dividing the total BTU content of the fuel burned by the resulting kWh’s generated. Heat rates can be expressed as either gross or net heat rates, depending whether the electricity output measured is gross or net generation and is generally expressed as BTU per net kWh.
Hedge Reset		Net settlement of long-term power contracts and gas swaps by negotiating prices to current market completed in November 2006
IGCC		Integrated Gasification Combined Cycle
IRS		Internal Revenue Service
ISO		Independent System Operator, also referred to as Regional Transmission Organizations, or RTO
ISO-NE		ISO New England Inc.
ITISA		Itiquira Energetica S.A.
kV		Kilovolts
kW		Kilowatts
kWh		Kilowatt-hours
LIBOR		London Inter-Bank Offer Rate
LTIP		Long-Term Incentive Plan
MACT		Maximum Achievable Control Technology
Merit Order		A term used for the ranking of power stations in order of ascending marginal cost
MIBRAG		Mitteldeutsche Braunkohlengesellschaft mbH
Moody’s		Moody’s Investors Services, Inc. — a credit rating agency
MMBtu		Million British Thermal Units
MOU		Memorandum of Understanding
MRTU		Market Redesign and Technology Upgrade
MVA		Megavolt-ampere
MW		Megawatts
MWh		Saleable megawatt hours net of internal/parasitic load megawatt-hours
MWt		Megawatts Thermal
NAAQS		National Ambient Air Quality Standards
NEPOOL		New England Power Pool
Net Baseload Capacity		Nominal summer net megawatt capacity of power generation adjusted for ownership and parasitic load, and excluding capacity from mothballed units as of December 31, 2008
Net Capacity Factor		The net amount of electricity that a generating unit produces over a period of time divided by the net amount of electricity it could have produced if it had run at full power over that time period. The net amount of electricity produced is the total amount of electricity generated minus the amount of electricity used during generation.
Net Exposure		Counterparty credit exposure to NRG, net of collateral
Net Generation		The net amount of electricity produced, expressed in kWh’s or MWh’s, that is the total amount of electricity generated (gross) minus the amount of electricity used during generation.
NINA		Nuclear Innovation North America LLC
NO_x		Nitrogen oxide
NOL		Net Operating Loss
NOV		Notice of Violation
NPNS		Normal Purchase Normal Sale
NRC		United States Nuclear Regulatory Commission
NRG Retail		NRG Retail LLC
NSR		New Source Review
NYISO		New York Independent System Operator
OCI		Other Comprehensive Income


		GLOSSARY OF TERMS (continued)

Padoma		Padoma Wind Power LLC
Phase II 316(b) Rule		A section of the Clean Water Act regulating cooling water intake structures
PJM		PJM Interconnection, LLC
PJM market		The wholesale and retail electric market operated by PJM primarily in all or parts of Delaware, the District of Columbia, Illinois, Maryland, New Jersey, Ohio, Pennsylvania, Virginia and West Virginia
PMI		NRG Power Marketing, LLC, a wholly-owned subsidiary of NRG which procures transportation and fuel for the Company’s generation facilities, sells the power from these facilities, and manages all commodity trading and hedging for NRG
Powder River Basin, or PRB, Coal		Coal produced in northeastern Wyoming and southeastern Montana, which has low sulfur content
PPA		Power Purchase Agreement
PUCT		Public Utility Commission of Texas
Reliant Retail		Reliant Energy Inc.’s Texas electric retail business operations
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 revolving credit facility which matures on February 2, 2011
RGGI		Regional Greenhouse Gas Initiative
ROIC		Return on Invested Capital
RPM		Reliability Pricing Model — term for capacity market in PJM market
RTO		Regional Transmission Organization, also referred to as an Independent System Operators, or ISO
S&P		Standard & Poor’s, a credit rating agency
Sarbanes-Oxley		Sarbanes — Oxley Act of 2002 (as amended)
SEC		United States Securities and Exchange Commission
Securities Act		The Securities Act of 1933, as amended
Senior Credit Facility		NRG’s senior secured facility, which is comprised of a Term Loan Facility and a $1.3 billion Synthetic Letter of Credit Facility which mature on February 1, 2013, and a $1 billion Revolving Credit Facility, which matures on February 2, 2011
Senior Notes		The Company’s $4.7 billion outstanding unsecured senior notes consisting of $1.2 billion of 7.25% senior notes due 2014, $2.4 billion of 7.375% senior notes due 2016 and $1.1 billion of 7.375% senior notes due 2017
SFAS		Statement of Financial Accounting Standards issued by the FASB
SFAS 109		SFAS No. 109, “Accounting for Income Taxes”
SFAS 123R		SFAS No. 123 (revised 2004), “Share-Based Payment”
SFAS 133		SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” as amended
SFAS 141R		SFAS No. 141 (revised 2007), “Business Combinations”
SFAS 142		SFAS No. 142, “Goodwill and Other Intangible Assets”
SFAS 157		SFAS No. 157, “Fair Value Measurement”
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”
Sherbino		Sherbino I Wind Farm LLC
SO₂		Sulfur dioxide
SOP		Statement of Position issued by the American Institute of Certified Public Accountants
SOP 90-7		Statement of Position 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code”
STP		South Texas Project — nuclear generating facility located near Bay City, Texas in which NRG owns a 44% Interest
STPNOC		South Texas Project Nuclear Operating Company
Synthetic Letter of Credit Facility		NRG’s $1.3 billion senior secured synthetic letter of credit facility which matures on February 1, 2013
TANE		Toshiba American Nuclear Energy Corporation
TANE Facility		NINA’s $500 million credit facility from TANE which matures on February 24, 2012
TCEQ		Texas Commission on Environmental Quality


		GLOSSARY OF TERMS (continued)

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

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 for per share amounts)	2009			2008

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

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

Total operating costs and expenses		1,043			1,052

Operating Income		615			250

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

Total other expense		(119	)		(151	)

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

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

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

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


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

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

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

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


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

Net Income	$	198		$	49

See notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS


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

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

Total current assets		7,665			8,492

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

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

Total other assets		4,989			4,771

Total Assets	$	24,198			$ 24,808

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

Total current liabilities		5,585			6,581

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

Total non-current liabilities		10,899			10,857

Total Liabilities		16,484			17,438

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

Total Stockholders’ Equity		7,467			7,123

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

See notes to condensed consolidated financial statements.

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


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

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

Net Cash Provided by Operating Activities		139			60

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

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

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

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

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

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

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

See notes to condensed consolidated financial statements.

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

Note 1 — Basis of Presentation

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

The accompanying unaudited interim condensed consolidated financial statements have been prepared in accordance with the SEC’s regulations for interim financial information and with the instructions to Form 10-Q. Accordingly, they do not include all of the information and notes required by generally accepted accounting principles for complete financial statements. The accounting policies NRG follows are set forth in Note 2, Summary of Significant Accounting Policies, to the Company’s financial statements in its Annual Report on Form 10-K for the year ended December 31, 2008. 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, 2009, the results of operations for the three months ended March 31, 2009 and 2008, and cash flows for the three months ended March 31, 2009 and 2008. Certain prior-year amounts have been reclassified for comparative purposes.

Recent Developments – Reliant Retail Acquisition

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

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

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

Use of Estimates

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

Cash and Cash Equivalents

Cash and cash equivalents at March 31, 2009 are predominantly held in money market funds invested in treasury securities, treasury repurchase agreements or government agency debt.

Other Cash Flow Information

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

Recent Accounting Developments

The Company adopted SFAS No. 141 (revised 2007), Business Combinations, or SFAS 141R, on January 1, 2009. The provisions of SFAS 141R are applied prospectively to business combinations for which the acquisition date occurs after January 1, 2009. The statement requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at fair value at the acquisition date. It also recognizes and measures the goodwill acquired or a gain from a bargain purchase in the business combination and determines what information to disclose to enable users of an entity’s financial statements to evaluate the nature and financial effects of the business combination. In addition, transaction costs are required to be expensed as incurred. The Company has applied the provisions of SFAS 141R to the Reliant Retail acquisition, and has expensed $12 million in transactions costs related to the acquisition during the three months ended March 31, 2009. As discussed further in Note 12, Income Taxes, any future reductions to existing net deferred tax assets or valuation allowances, and changes to uncertain tax benefits, as they relates to Fresh Start or previously completed acquisitions, occurring after January 1, 2009 will be recorded to income tax expense rather than additional paid-in capital or goodwill, respectively.

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

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

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

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

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


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

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

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

In April 2009, the FASB issued FSP No. FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments, or FSP 107-1 and APB 28-1. This FSP amends FASB Statement No. 107, Disclosures about Fair Value of Financial Instruments, to require disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. This FSP also amends APB Opinion No. 28, Interim Financial Reporting, to require those disclosures in summarized financial information at interim reporting periods. This FSP applies to all financial instruments within the scope of Statement 107 held by publicly traded companies, as defined by Opinion 28. This FSP is effective for interim reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. FSP FAS 107-1 and APB 28-1 does not require disclosures for earlier periods presented for comparative purposes at initial adoption. In periods after initial adoption, this FSP requires comparative disclosures only for periods ending after initial adoption. The enhanced disclosure requirements are relevant to NRG but will not have an impact on the Company’s results of operations, financial position, or cash flows.

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

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

	•		FSP No. FAS 142-3, Determination of the Useful Life of Intangible Assets
	•		FSP No. FAS 157-2, Effective Date of FASB Statement No. 157
	•		SFAS No. 161, Disclosures About Derivative Instruments and Hedging Activities
	•		FSP No. FAS 132(R)-1, Employers’ Disclosures about Postretirement Benefit Plan Assets
	•		EITF No. 07-5, Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock
	•		EITF No. 08-5, Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement
	•		EITF No. 08-6, Equity Method Investment Accounting Considerations

Note 2 — Comprehensive Income/(Loss)

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


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

Net income	$	198		$	49

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

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

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

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


(In millions)

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

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

Note 3 — Investments Accounted for by the Equity Method

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

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

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

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

Note 4 — Fair Value of Financial Instruments

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


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

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

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

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

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

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


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

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

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

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

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

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

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

Note 5 — Nuclear Decommissioning Trust Fund

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


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

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

Total	$	286	$	303

Note 6 — Accounting for Derivative Instruments and Hedging Activities

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

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

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

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

Energy-Related Commodities

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

	•		Forward contracts, which commit NRG to sell energy commodities or purchase fuels in the future.

	•		Futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial instrument.

	•		Swap agreements, which require payments to or from counter-parties based upon the differential between two prices for a predetermined contractual, or notional, quantity.

	•		Option contracts, which convey the right or obligation to buy or sell a commodity.

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

	•		Fixing the price for a portion of anticipated future electricity sales through the use of various derivative instruments including gas collars and swaps at a level that provides an acceptable return on the Company’s electric generation operations.

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

	•		Fixing the price of a portion of anticipated energy purchases to supply NRG’s load-serving customers.

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

Interest Rate Swaps

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

Volumetric Underlying Derivative Transactions

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


		Total Volume
Commodity	Units	(In millions)

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

Fair Value of Derivative Instruments

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


	Fair Value
(In millions)		Derivatives Asset		Derivatives Liability

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

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


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

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

Total Derivatives			$ 5,010		$ 3,420

Impact of Derivative Instruments on the Statement of Financial Performance

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


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

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

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

Amount of

Location of

Amount of

Location of

Amount of

gain/(loss)

recognized in OCI

reclassified from

recognized in

(In millions)

(effective portion)

Accumulated

income

Three months ended March 31, 2009

after tax

OCI into Income

(ineffective portion)

Interest rate contracts

Interest expense

)

Interest expense

—

Commodity contracts

161

Operating
revenue

112

Operating revenue

Total

173

111

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


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

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

Credit Risk Related Contingent Features

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

Concentration of Credit Risk

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

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

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

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


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

Coal suppliers		2	%
Financial institutions		63
Utilities, energy, merchants, marketers and other		32
ISOs		3

Total		100	%


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

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

Total		100	%


(a)		Credit exposure excludes California tolling, uranium, coal transportation/railcar leases, New England Reliability-Must-Run, cooperative load contracts and Texas Westmoreland coal contracts.

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

Accumulated Other Comprehensive Income

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


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

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

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

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


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

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

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

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

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

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

Statement of Operations

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

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


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

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

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


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

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

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

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

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

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

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

Note 7 — Long-Term Debt

Senior Credit Facility

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

TANE Facility

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

Debt Related to Capital Allocation Program

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

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

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

Adoption of FSP APB 14-1 — As discussed in Note 1, Basis of Presentation, the Company adopted FSP APB 14-1 on January 1, 2009. The following table summarizes certain information related to the CSF Debt in accordance with FSP APB 14-1:


	March 31,			December 31,
	2009			2008

Equity Component
Additional Paid-in Capital	$	14		$	14

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

Net carrying amount	$	327		$	325

The unamortized discount will be amortized through the maturity of the CSF Debt. The CSF I debt has a maturity date of June 2010 and the CSF II debt has a maturity date October 2009. Interest expense for the CSF Debt, including the debt discount amortization for the three months ended March 31, 2009 and 2008 was $9 million and $10 million, respectively. The effective interest rate as of March 31, 2009 was 11.4% for the CSF I debt and 12.0% for the CSF II debt.

Subsequent events

Dunkirk Power LLC Tax-Exempt Bonds — On April 15, 2009, NRG executed a $59 million tax-exempt bond financing through its wholly owned subsidiary, Dunkirk Power LLC. The bonds were issued by the County of Chautauqua Industrial Development Agency and will be applied towards construction of emission control equipment on the Dunkirk Generating Station in Dunkirk, NY. The bonds initially bear weekly interest based on the Securities Industry and Financial Markets Association, or SIFMA, rate, have a maturity date of April 1, 2042, and are enhanced by a letter of credit under the Company’s Revolving Credit Facility covering amounts drawn on the facility. The initial proceeds were $31 million with the remaining balance being released over time as construction costs are paid.

GenConn Energy LLC related financings — On April 27, 2009, a wholly owned subsidiary of NRG closed on an equity bridge loan facility, or EBL, in the amount of $121.5 million from a syndicate of banks. The purpose of the EBL is to fund the Company’s proportionate share of the project construction costs required to be contributed into GenConn Energy LLC, or GenConn, a 50% equity method investment of the Company. The EBL, which is fully collateralized with a letter of credit issued under the Company’s Synthetic Letter of Credit Facility, will bear interest at a rate of LIBOR plus 2% on drawn amounts. The EBL will mature on the earlier of the commercial operations date of the Middletown project or July 26, 2011. The EBL also features a mandatory prepayment of the portion of the loan utilized for the Devon project (approximately $56 million) becoming due on the earlier of Devon’s commercial operations date or January 27, 2011. The initial proceeds of the EBL were $61 million and the remaining amounts will be drawn as necessary to fund construction costs.

At the same time, GenConn secured financing from the same syndicate of banks for 50% of its project construction costs through a 7-year term loan facility, as well as a 5 year revolving working capital loan and letter of credit facility, collectively the GenConn Facility. The aggregate credit amount secured under the GenConn Facility, which is non-recourse to NRG, was $291 million, including $48 million for the revolving facility. No amounts were immediately drawn under the GenConn Facility.

Note 8 — Changes in Capital Structure

The following table reflects the changes in NRG’s common stock issued and outstanding during the three months ended March 31, 2009:


	Authorized		Issued		Treasury			Outstanding

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

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

Employee Stock Purchase Plan

As of March 31, 2009, there remained 458,294 shares of treasury stock reserved for issuance under the ESPP.

5.75% Preferred Stock

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


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

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

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

4% Preferred Stock

As of March 31, 2009, 210 shares of the 4% Preferred Stock were converted into 10,500 shares of common stock in 2009.

Note 9 — Equity Compensation

Non-Qualified Stock Options, or NQSO’s

The following table summarizes the Company’s NQSO activity as of March 31, 2009, and changes during the three months then ended:


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

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

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

The weighted average grant date fair value of NQSO’s granted for the three months ended March 31, 2009, was $8.55.

Restricted Stock Units, or RSU’s

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


				Weighted Average
				Grant-Date
	Units			Fair Value Per Unit

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

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

Performance Units, or PU’s

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


				Weighted Average
				Grant- Date
	Units			Fair Value Per Unit

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

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

In the first quarter 2009, there were no performance unit payouts in accordance with the provisions.

Note 10 — Earnings Per Share

Basic earnings per share attributable to NRG common stockholders is computed by dividing net income attributable to NRG adjusted for accumulated preferred stock dividends by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the year are weighted for the portion of the year that they were outstanding. The 12,000,000 shares outstanding under the Share Lending Agreements with CS affiliates are not treated as outstanding for earnings per share purposes because the CS affiliates must return all borrowed shares (or identical shares) upon termination of the Agreements. See Note 7 – Long-Term Debt, for more information on the Share Lending Agreements. Diluted earnings per share attributable to NRG common stockholders is computed in a manner consistent with that of basic earnings per share while giving effect to all potentially dilutive common shares that were outstanding during the period.

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


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

*Basic earnings per share attributable to NRG common stockholders*
Numerator:
Income from continuing operations, net of income taxes	$	198		$	45
Dividends for preferred shares		(14	)		(14	)

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

Denominator:
Weighted average number of common shares outstanding		237.1			236.3
*Basic earnings per share:*
Income from continuing operations	$	0.78		$	0.13
Income from discontinued operations, net of income taxes		—			0.02

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

*Diluted earnings per share attributable to NRG common stockholders*
Numerator:
Net income available to common stockholders from continuing operations	$	184		$	31
Add preferred stock dividends for dilutive preferred stock		10			—

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

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

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

Total dilutive shares		275.4			245.3
*Diluted earnings per share:*
Income from continuing operations	$	0.70		$	0.12
Income from discontinued operations, net of income taxes		—			0.02

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

Effects on Earnings per Share

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


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

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

Total		29.0		67.8

Note 11 — Segment Reporting

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


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

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

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

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


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

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

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

Note 12 — Income Taxes

Effective Tax Rate

Income taxes included in continuing operations were as follows:


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

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

For the three months ended March 31, 2009 and 2008, NRG’s overall effective tax rate on continuing operations was different than the statutory rate of 35% primarily due to state income taxes and an increase in valuation allowance as a result of capital losses generated in the quarter for which there are no projected capital gains or available tax planning strategies. In addition, NRG’s overall effective tax rate on continuing operations for the three months ended March 31, 2008 was impacted by a taxable dividend from foreign operations.

Valuation Allowance

As of March 31, 2009, the Company’s valuation allowance was increased by approximately $96 million primarily due to losses generated in the first quarter from derivative trading activity which require capital treatment for tax purposes. The Company reduced its foreign valuation allowance by approximately $1 million.

Uncertain tax benefits

NRG has identified certain unrecognized tax benefits whose after-tax value is $556 million, which would impact the Company’s income tax expense.

As of March 31, 2009, NRG has recorded a $272 million non-current tax liability for unrecognized tax benefits, resulting from taxable earnings for the period for which there are no NOLs available to offset for financial statement purposes. NRG has accrued interest related to these unrecognized tax benefits of approximately $4 million for the three months ended March 31, 2009, and has accrued approximately $12 million since adoption. The Company recognizes interest and penalties related to unrecognized tax benefits in income tax expense.

NRG is subject to examination by taxing authorities for income tax returns filed in the US federal jurisdiction and various state and foreign jurisdictions including major operations located in Germany and Australia. The Company is no longer subject to US federal income tax examinations for years prior to 2002. With few exceptions, state and local income tax examinations are no longer open for years before 2002. The Company’s significant foreign operations are also no longer subject to examination by local jurisdictions for years prior to 2000. The Company continues to be under examination by the Internal Revenue Service.

Note 13 — Benefit Plans and Other Postretirement Benefits

NRG Defined Benefit Plans

NRG sponsors and operates three defined benefit pension and other postretirement plans. The NRG Plan for Bargained Employees and the NRG Plan for Non-Bargained Employees are maintained solely for eligible legacy NRG participants. A third plan, the Texas Genco Retirement Plan, is maintained for participation solely by eligible Texas-based employees. The total amount of employer contributions paid for the three months ended March 31, 2009 was $6 million. NRG expects to make $24 million in further contributions for the remainder of 2009. The total 2009 planned contribution of $30 million was a decrease of $30 million from the expected contributions as disclosed in Note 12 — Benefit Plans and Other Postretirement Benefits, in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008. This decrease in the 2009 expected contributions is due to the adoption by the Company in March 2009 of the new funding method options now available. The new methods were made allowable under new IRS guidance on the application of recent Congressional legislation on funding requirements.

The net periodic pension cost related to all of the Company’s defined benefit pension plans include the following components:


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

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

Net periodic benefit cost	$	5		$	5

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


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

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

Net periodic benefit cost	$	3	$	2

STP Defined Benefit Plans

NRG has a 44% undivided ownership interest in South Texas Project, or STP. South Texas Project Nuclear Operating Company, or STPNOC, which operates and maintains STP, provides its employees a defined benefit pension plan as well as postretirement health and welfare benefits. Although NRG does not sponsor the STP plan, it reimburses STPNOC for 44% of the contributions made towards its retirement plan obligations. There were no employer contributions reimbursed to STPNOC for the three months ended March 31, 2009. The Company recognized net periodic costs related to its 44% interest in STP defined benefits plans of $3 million and $2 million for the three months ended March 31, 2009 and 2008, respectively.

Note 14 — Commitments and Contingencies

Commitments

Fuel Commitments

NRG enters into long-term contractual arrangements to procure fuel and transportation services for the Company’s generation assets. NRG’s total net coal commitments, which span from 2009 through 2012, decreased by approximately $120 million during the three months ended March 31, 2009 as the 2009 monthly commitments were settled. In addition, NRG’s natural gas purchase commitments decreased by approximately $124 million during the three months ended March 31, 2009, as the 2009 monthly commitments were settled and average natural gas prices decreased.

First and Second Lien Structure

NRG has granted first and second liens to certain counterparties on substantially all of the Company’s assets to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or MWh equivalents. The Company’s lien counterparties may have a claim on NRG’s assets to the extent market prices exceed the hedged price. As of March 31, 2009, and April 23, 2009, there was no exposure to out-of-the-money positions to counterparties on hedges under either the first or second liens.

RepoweringNRG Initiatives

NRG has capitalized $32 million through March 31, 2009, for the repowering of its El Segundo generating facility in California. As a result of permitting delays related to on-going Natural Resource Defense Counsel claims, the El Segundo project will not reach its original completion date of June 1, 2011. The Company is contemplating certain PPA modifications including the commercial operations date.

Contingencies

Set forth below is a description of the Company’s material legal proceedings. The Company believes that it has valid defenses to these legal proceedings and intends to defend them vigorously. Pursuant to the requirements of SFAS No. 5, Accounting for Contingencies, or SFAS 5, and related guidance, NRG records reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. In addition, legal costs are expensed as incurred. Management has assessed each of the following matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, the Company is unable to predict the outcome of these legal proceedings or reasonably estimate the scope or amount of any associated costs and potential liabilities. As additional information becomes available, management adjusts its assessment and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of the Company’s liabilities and contingencies could vary from its currently recorded reserves and such differences could be material.

In addition to the legal proceedings noted below, NRG and its subsidiaries are party to other litigation or legal proceedings arising in the ordinary course of business. In management’s opinion, the disposition of these ordinary course matters will not materially adversely affect NRG’s consolidated financial position, results of operations, or cash flows.

Exelon Related Litigation

Delaware Chancery Court

On November 11, 2008, Exelon and its wholly-owned subsidiary Exelon Xchange filed a complaint against NRG and NRG’s Board of Directors. The complaint alleges, among other things, that NRG’s Board of Directors failed to give due consideration and to take appropriate action in response to the acquisition proposal announced by Exelon on October 19, 2008, in which Exelon offered to acquire all of the outstanding shares of NRG common stock at an exchange ratio of 0.485 Exelon shares for each NRG common share. On November 14, 2008, NRG and NRG’s Board of Directors filed a motion to dismiss Exelon’s complaint on the grounds that it failed to state a claim upon which relief can be granted. On March 16, 2009, prior to responding to the motion to dismiss, Exelon and Exelon Xchange filed an amended complaint. The amended complaint seeks, among other things, declaratory and injunctive relief: (1) declaring that NRG and its Board of Directors breached its fiduciary duties by summarily rejecting the October 19, 2008 Exelon offer, by resorting to defensive measures to interfere with Exelon’s tender offer, and by making false and misleading statements to NRG stockholders; (2) compelling NRG and its Board of Directors to approve the Exelon tender offer by waiving the application of Section 203 of the Delaware General Corporation Law; (3) compelling NRG and its Board of Directors from taking any actions with respect to regulatory authorities that would thwart or interfere with the Exelon tender offer; and (4) compelling NRG and its Board of Directors to correct any false and misleading statements to NRG stockholders and to disclose all material facts necessary for NRG stockholders to make informed decisions regarding the October 19, 2008 Exelon offer. On April 17, 2009, NRG and NRG’s Board of Directors filed a partial motion to dismiss the amended complaint asserting that many of the claims are subject to the business judgment rule, are premature, and should be dismissed for failure to state a claim upon which relief can be granted. A schedule for briefing the motion will be agreed by the parties or set by the court.

On December 11, 2008, the Louisiana Sheriffs’ Pension & Relief Fund and City of St. Claire Shores Police & Fire Retirement System, on behalf of themselves and all others similarly situated, served a previously filed complaint on NRG and its Board of Directors alleging substantially similar allegations as the Exelon complaint. On December 23, 2008, NRG and NRG’s Board of Directors filed a motion to dismiss the complaint on the grounds that it failed to state a claim upon which relief can be granted. On March 16, 2009, prior to responding to the motion to dismiss, these plaintiffs filed an amended complaint against only NRG’s Board of Directors. The amended complaint seeks, among other things, declaratory and injunctive relief: (1) declaring that it is a proper class action; (2) declaring that the NRG Board of Directors breached its fiduciary duties by summarily rejecting the October 19, 2008, Exelon offer and by resorting to defensive measures designed to prevent any potential acquirer from entering into a value-maximizing transaction with NRG; (3) compelling NRG’s Board of Directors to engage in a dialogue with Exelon to more fully understand the October 19, 2008, offer and to determine the potential for any improvement thereon; (4) enjoining NRG from proceeding with the acquisition of Reliant Energy’s retail business; (5) enjoining the NRG’s Board of Directors from taking any actions designed to block a transaction with Exelon; and (6) awarding plaintiffs their costs and fees. On April 17, 2009, the NRG Board of Directors filed a motion to dismiss the amended complaint asserting that it fails to state a claim upon which relief can be granted. A schedule for briefing the motion will be agreed by the parties or set by the court.

On April 3, 2009, the Louisiana Sheriffs’ Pension & Relief Fund and City of St. Claire Shores Police & Fire Retirement System filed (1) a motion for injunctive relief to rescind the appointment of Pastor Kirbyjon H. Caldwell to NRG’s Board of Directors and to prevent the NRG Board from taking any action that would impede the vote for directors at the next annual meeting of NRG stockholders; and (2) a motion to expedite the injunction proceeding. The NRG Board of Directors filed its opposition to the motions on April 8, 2009, a telephonic hearing was held on April 9, 2009, and on April 14, 2009, the court denied both motions.

Mercer County, New Jersey Superior Court

On January 6, 2009, three lawsuits previously filed against NRG and NRG’s Board of Directors on behalf of individual shareholders and all others similarly situated were consolidated into one case in the Law Division of the Superior Court of Mercer County, New Jersey. On January 21, 2009, the plaintiffs filed an Amended Consolidated Complaint in which they allege a single count of breach of fiduciary duty against NRG’s Board of Directors and seek injunctive relief: (1) declaring that the action is a class action and certifying plaintiffs as class plaintiffs and counsel as class counsel; (2) declaring that defendants breached their fiduciary duties by summarily rejecting the Exelon offer; (3) ordering defendants to negotiate with respect to the Exelon offer or with respect to another transaction to maximize shareholder value; (4) ordering defendants to exempt Exelon’s offer from Section 203 of the Delaware General Corporations Law; (5) awarding compensatory damages including interest; (6) awarding plaintiffs costs and fees; and (7) granting other relief the Court deems proper. On February 20, 2009, NRG’s Board of Directors filed a motion to dismiss the amended consolidated complaint for failure to state a claim or, in the alternative, to stay the action in favor of the Delaware Chancery Court proceedings. On March 19, 2009, the plaintiffs filed their response and on April 6, 2009, NRG’s Board of Directors filed its reply. On April 17, 2009, oral argument was held on the NRG Board of Director’s motion to dismiss. Additional oral argument will be scheduled by the court.

California Department of Water Resources

This matter concerns, among other contracts and other defendants, the California Department of Water Resources, or CDWR, and its wholesale power contract with subsidiaries of WCP (Generation) Holdings, Inc., or WCP. The case originated with a February 2002 complaint filed by the State of California alleging that many parties, including WCP subsidiaries, overcharged the State of California. For WCP, the alleged overcharges totaled approximately $940 million for 2001 and 2002. The complaint demanded that the Federal Energy Regulatory Commission, or FERC, abrogate the CDWR contract and sought refunds associated with revenues collected under the contract. In 2003, the FERC rejected this complaint, denied rehearing, and the case was appealed to the US Court of Appeals for the Ninth Circuit where oral argument was held on December 8, 2004. On December 19, 2006, the Ninth Circuit decided that in the FERC’s review of the contracts at issue, the FERC could not rely on the Mobile-Sierra standard presumption of just and reasonable rates, where such contracts were not reviewed by the FERC with full knowledge of the then existing market conditions. WCP and others sought review by the US Supreme Court. WCP’s appeal was not selected, but instead held by the Supreme Court. In the appeal that was selected by the Supreme Court, on June 26, 2008, the Supreme Court ruled: (1) that the Mobile-Sierra public interest standard of review applied to contracts made under a seller’s market-based rate authority; (2) that the public interest “bar” required to set aside a contract remains a very high one to overcome; and (3) that the Mobile-Sierra presumption of contract reasonableness applies when a contract is formed during a period of market dysfunction unless (a) such market conditions were caused by the illegal actions of one of the parties or (b) the contract negotiations were tainted by fraud or duress. In this related case, the US Supreme Court affirmed the Ninth Circuit’s decision agreeing that the case should be remanded to FERC to clarify FERC’s 2003 reasoning regarding its rejection of the original complaint relating to the financial burdens under the contracts at issue and to alleged market manipulation at the time these contracts were formed. As a result, the US Supreme Court then reversed and remanded the WCP CDWR case to the Ninth Circuit for treatment consistent with its June 26, 2008 decision in the related case. On October 20, 2008, the Ninth Circuit asked the

parties in the remanded CDWR case, including WCP and the FERC, whether that Court should answer a question the US Supreme Court did not address in its June 26, 2008, decision; whether the Mobile-Sierra doctrine applies to a third-party that was not a signatory to any of the wholesale power contracts, including the CDWR contract, at issue in that case. Without answering that reserved question, on December 4, 2008, the Ninth Circuit vacated its prior opinion and remanded the WCP CDWR case back to the FERC for proceedings consistent with the US Supreme Court’s June 26, 2008, decision. On December 15, 2008, WCP and the other seller-defendants filed with FERC a Motion for Order Governing Proceedings on Remand. On January 14, 2009, the Public Utilities Commission of the State of California filed an Answer and Cross Motion for an Order Governing Procedures on Remand, and on January 28, 2009, WCP and the other seller-defendants filed their reply.

At this time, while NRG cannot predict with certainty whether WCP will be required to make refunds for rates collected under the CDWR contract or estimate the range of any such possible refunds, a reconsideration of the CDWR contract by the FERC with a resulting order mandating significant refunds could have a material adverse impact on NRG’s financial position, statement of operations, and statement of cash flows. As part of the 2006 acquisition of Dynegy’s 50% ownership interest in WCP, WCP and NRG assumed responsibility for any risk of loss arising from this case, unless any such loss was deemed to have resulted from certain acts of gross negligence or willful misconduct on the part of Dynegy, in which case any such loss would be shared equally between WCP and Dynegy.

On April 27, 2009, the US Supreme Court granted certiorari in an unrelated proceeding involving the Mobile-Sierra doctrine that may affect the standard of review applied to the CDWR contract on remand before the FERC. Specifically, on March 18, 2008, the U.S. Court of Appeals for the DC Circuit rejected the appeals filed by the Attorneys General of the State of Connecticut and Commonwealth of Massachusetts regarding the settlement that established the current New England capacity market. That settlement, filed with FERC on March 7, 2006, provides for interim capacity transition payments for all generators in New England for the period starting December 1, 2006 through May 31, 2010, and for the Forward Capacity Market thereafter. The Court of Appeals rejected all substantive challenges to the settlement, but sustained one procedural argument relating to the applicability of the Mobile-Sierra doctrine to non-settling parties. After the Court of Appeals denied rehearing en banc, NRG sought certiorari before the US Supreme Court, which was granted on April 27, 2009.

Louisiana Generating, LLC

On February 11, 2009, the US Department of Justice acting at the request of the US Environmental Protection Agency, or USEPA, commenced a lawsuit against Louisiana Generating, LLC in federal district court in the Middle District of Louisiana alleging violations of the Clean Air Act, or CAA, at the Big Cajun II power plant. This is the same matter for which Notices of Violation, or NOVs, were issued to Louisiana Generating, LLC on February 15, 2005, and on December 8, 2006. Specifically, it is alleged that in the late 1990’s, several years prior to NRG’s acquisition of the Big Cajun II power plant from the Cajun Electric bankruptcy and several years prior to the NRG bankruptcy, modifications were made to Big Cajun II Units 1 and 2 by the prior owners without appropriate or adequate permits and without installing and employing the best available control technology, or BACT, to control emissions of nitrogen oxides and/or sulfur dioxides. The relief sought in the complaint includes a request for an injunction to: (1) preclude the operation of Units 1 and 2 except in accordance with the CAA; (2) order the installation of BACT on Units 1 and 2 for each pollutant subject to regulation under the CAA; (3) obtain all necessary permits for Units 1 and 2; (4) order the surrender of emission allowances or credits; (5) conduct audits to determine if any additional modifications have been made which would require compliance with the CAA’s Prevention of Significant Deterioration program; (6) award to the Department of Justice its costs in prosecuting this litigation; and (7) assess civil penalties of up to $27,500 per day for each CAA violation found to have occurred between January 31, 1997, and March 15, 2004, up to $32,500 for each CAA violation found to have occurred between March 15, 2004, and January 12, 2009, and up to $37,500 for each CAA violation found to have occurred after January 12, 2009.

On April 27, 2009, Louisiana Generating, LLC made several filings. First, it filed an objection in the Cajun Electric Cooperative Power, Inc.’s bankruptcy proceeding challenging the February 19, 2009, Motion for Final Decree, Discharge of the Trustee, and For Order Closing the Chapter 11 Case, to prevent the bankruptcy from closing. The objection was filed in the U.S. Bankruptcy Court for the Middle District of Louisiana. Second, it filed a complaint in the same bankruptcy proceeding in the same court seeking a judgment that: (i) it did not assume liability from Cajun Electric for any claims or other liabilities under environmental laws with respect to Big Cajun II that arose, or are based on activities that were undertaken, prior to the closing date of the acquisition; (ii) it is not otherwise the successor to Cajun Electric; and (iii) Cajun Electric and/or the Bankruptcy Trustee are exclusively liable for the violations alleged in the February 11, 2009, lawsuit to the extent that such claims are determined to have merit. Last, it filed in the federal district court for the Middle District of Louisiana a Motion for an Extension of Time to File Responsive Pleadings arguing that the court should extend the May 11, 2009, deadline to respond to the February 11, 2009, lawsuit until such time as directed by the court following resolution of Louisiana Generating, LLC’s Motion for Stay of Proceedings Pending Resolution of Certain Bankruptcy Actions filed concurrently with the Motion for an Extension of Time.

Citizens for Clean Power

On November 6, 2008, Citizens for Clean Power, or CCP, filed a notice of its intent to file a lawsuit under the CAA against Indian River Power, LLC, or IRP, seeking to enforce opacity limitations applicable to units 1, 2, 3, and 4. On January 5, 2009, the Delaware Department of Natural Resources and Environmental Control, or DNREC, filed a lawsuit relating to opacity issues against IRP in the Superior Court in Kent County, Delaware. On January 6, 2009, DNREC and IRP agreed to a consent order resolving the DNREC action in which IRP agreed to pay a $5,000 civil penalty and agreed to purchase for DNREC’s use an Ultrafine Particle Monitor for approximately $60,000. The consent order was filed with the court on February 6, 2009, and entered by the court on February 13, 2009, thereby precluding CCP’s ability under the CAA to commence its noticed lawsuit. On February 26, 2009, notwithstanding the entry of the consent order, CCP filed a complaint against IRP, in federal district court in Delaware. The complaint seeks injunctive and declarative relief in addition to civil penalties: (1) declaring that IRP violated the CAA through 6,304 opacity violations between 2004 and 2008; (2) seeking civil penalties of up to $32,500 for each such violation; (3) enjoining IRP from violating the CAA; (4) ordering IRP to assess and mitigate any environmental injuries caused by its emissions; and (5) awarding CCP its fees and costs. On March 25, 2009, IRP filed a motion to dismiss the complaint, on April 7, 2009, CCP filed its opposition, and on April 20, 2009, IRP filed its reply.

Disputed Claims Reserve

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

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. On December 18, 2008, NRG filed with the US Bankruptcy Court for the Southern District of New York a Closing Report and an Application for Final Decree Closing the Chapter 11 Case for NRG Energy, Inc. et al and on December 29, 2008, the court entered the Final Decree. As of December 21, 2008, the reserve held approximately $9.8 million in cash and 1,282,783 shares of common stock. On December 21, 2008, the Company issued an instruction letter to The Bank of New York Mellon to distribute all remaining cash and stock in the Disputed Claims Reserve to NRG’s creditors. On January 12, 2009, The Bank of New York Mellon commenced the distribution of all remaining cash and stock in the Disputed Claim Reserve to the Company’s creditors pursuant to NRG’s Chapter 11 bankruptcy plan.

Note 15 — Regulatory Matters

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.

PJM — By Order dated March 17, 2009, the US Court of Appeals for the DC Circuit denied the remaining appeals of the FERC orders establishing the RPM capacity market. In February of 2009, the entities representing load interests, including the New Jersey Board of Public Utilities, the District of Columbia Office of the People’s Counsel, and the Maryland Office of People’s Counsel, agreed to withdraw their appeals regarding the establishment of the RPM market design.

On May 30, 2008, the Maryland Public Service Commission together with other load interests, filed with FERC a complaint against PJM challenging the results of the RPM transition Base Residual Auctions for installed capacity, held between April 2007 and January 2008. The complaint sought to replace the auction-determined results for installed capacity for the 2008/2009, 2009/2010, and 2010/2011 delivery years with administratively-determined prices. On September 19, 2008, FERC dismissed the complaint. The parties representing load interests have sought rehearing of the dismissal of the complaint, and a reversal by FERC, could result in a refund obligation.

Note 16 — Environmental Matters

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

Environmental Capital Expenditures

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

Northeast Region

NRG operates electric generating units located in Connecticut, Delaware, Maryland, Massachusetts and New York which are subject to RGGI. These units must surrender one allowance for every US ton of CO₂ emitted with true up for 2009-2011 occurring in 2012. Allowances are partially allocated only in the state of Delaware. In 2008, NRG emitted approximately 12 million tonnes of CO₂ in RGGI states, although 2009 is tracking lower than 2008 year to date. NRG believes that to the extent CO₂will not be fully reflected in wholesale electricity prices, the direct financial impact on the Company is likely to be negative as costs will be incurred in the course of securing the necessary RGGI allowances and offsets at auction and in the market.

In January 2006, NRG’s Indian River Operations, Inc. received a letter of informal notification from the DNREC stating that the Company may be a potentially responsible party with respect to a historic captive landfill. On October 1, 2007, NRG signed an agreement with DNREC to investigate the site through the Voluntary Clean-up Program. On February 4, 2008, the DNREC issued findings that no further action is required in relation to surface water and that a previously planned shoreline stabilization project would adequately address shore line erosion. The landfill itself will require a further Remedial Investigation and Feasibility Study to determine the type and scope of any additional work required. Until the Remedial Investigation and Feasibility Study are completed, the Company is unable to predict the impact of any required remediation.

On May 29, 2008, the DNREC issued an invitation to NRG’s Indian River Operations, Inc. to participate in the development and performance of a Natural Resource Damage Assessment, or NRDA, at the Burton Island Old Ash Landfill. NRG is currently working with the DNREC and other trustees to close out the property.

Note 17 — Guarantees

NRG and its subsidiaries enter into various contracts that include indemnification and guarantee provisions as a routine part of the Company’s business activities. Examples of these contracts include asset purchases and sale agreements, commodity sale and purchase agreements, joint venture agreements, EPC agreements, operation and maintenance agreements, service agreements, settlement agreements, and other types of contractual agreements with vendors and other third parties, as well as affiliates. These contracts generally indemnify the counterparty for tax, environmental liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. In some cases, NRG’s maximum potential liability cannot be estimated, since the underlying agreements contain no limits on potential liability.

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

In connection with the agreement to sell its 50% ownership interest in Mibrag B.V., NRG signed an agreement guaranteeing the performance of its subsidiary Lambique Beheer under the purchase and sale agreement. The Company’s guarantee is limited to EUR 206 million, which represents the expected sales proceeds including expected interest through closing. In addition, the Company guaranteed the performance of NRGenerating International B.V. under a currency exchange agreement related to the proceeds of the sale of MIBRAG. The guarantee is limited to $35 million. NRG has no reason to believe that the Company currently has any material liability relating to such routine indemnification obligations.

NRG signed a guarantee agreement on behalf of its subsidiary NRG Retail, LLC guaranteeing the payment and performance of its obligations under the LLC Membership Interest Purchase Agreement and related agreements with Reliant Energy in connection with the purchase of its retail business, including the purchase price of $287.5 million and an additional $2.6 million for additional marketing services agreed upon as part of the transaction. NRG has no reason to believe that the Company currently has any material liability relating to such routine indemnification obligations.

Note 18 — Condensed Consolidating Financial Information

As of March 31, 2009, the Company had $1.2 billion of 7.25% Senior Notes due 2014, $2.4 billion of 7.375% Senior Notes due 2016 and $1.1 billion 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, 2009:


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


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

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, 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, 2009


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

Operating Revenues
Total operating revenues	$	1,566		$	95		$	—		$	(3	)	$	1,658

Operating Costs and Expenses
Cost of operations		698			68			3			(3	)		766
Depreciation and amortization		158			10			1			—			169
General and administrative		17			3			75			—			95
Development costs		2			2			9			—			13

Total operating costs and expenses		875			83			88			(3	)		1,043

Operating Income/(Loss)		691			12			(88	)		—			615
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries		21			—			397			(418	)		—
Equity in earnings of unconsolidated affiliates		1			21			—			—			22
Other income/(loss), net		1			(7	)		3			—			(3	)
Interest expense		(48	)		(21	)		(69	)		—			(138	)

Total other income/(expense)		(25	)		(7	)		331			(418	)		(119	)

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

Net Income attributable to NRG Energy, Inc.	$	414		$	4		$	198		$	(418	)	$	198


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

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
March 31, 2009


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

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

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

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

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

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

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

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

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

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

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

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

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

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


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

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2009


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

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

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

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

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

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

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

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

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

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

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


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

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	$	1,201		$	101		$	—		$	—		$	1,302

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

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

Operating Income/(Loss)		300			23			(73	)		—			250
Other Income/(Expense)
Equity in earnings/(losses) of consolidated subsidiaries		72			(18	)		142			(196	)		—
Equity in losses of unconsolidated affiliates		(2	)		(2	)		—			—			(4	)
Other income, net		1			3			5			—			9
Interest expense		(51	)		(21	)		(84	)		—			(156	)

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

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

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

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


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

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


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

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

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


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

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

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

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

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

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

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

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

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

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

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


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

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


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

Cash Flows from Operating Activities
Net income attributable to NRG Energy, Inc.	$	199		$	(3	)	$	49		$	(196	)	$	49

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

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

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

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

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

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

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

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

(a)

All significant intercompany transactions have been eliminated in consolidation.

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

In this discussion and analysis, NRG discusses and explains its financial condition and results of operations, including:

	•		Factors which affect the Company’s business;

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

	•		Changes in earnings and costs between periods;

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

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

	•		Expected future expenditures for capital projects; and

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

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

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

	•		Strategy section;

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

	•		Critical Accounting Policies and Estimates section.

The discussion and analysis below has been organized as follows:

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

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

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

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

Executive Summary

Introduction and Overview

NRG is a wholesale power generation company with a significant presence in major competitive power markets in the US. 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 regional markets in the US and select international markets where its generating assets are located.

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

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

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

NRG’s Business Strategy

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

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

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

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

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

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

Business Environment – Financial Credit Market Availability and Domestic Recession

In 2009, the nation’s economy continues to experience recessionary factors which include tight credit markets. Power generation companies are capital intensive and, as such, rely on the credit markets for liquidity and for the financing of power generation investments. In addition, economic recessions historically result in lower power demand, power prices, and fuel prices. NRG has a diversified liquidity program, with $3.1 billion in total liquidity, excluding funds deposited by counterparties, and a first and second lien structure that enables significant strategic hedging while reducing requirements for the posting of cash or letters of credit as collateral. NRG expects to continue to manage commodity price volatility through its strategic hedging program, under which the Company expects to hedge revenues and fuel costs. This program should provide the Company with the flexibility to enter into hedges opportunistically, such as when gas prices are increasing, while at the same time protecting NRG against longer-term volatility in the commodity markets. The Company believes that an economic recession is unlikely to have a material impact on the Company’s cash generation in the near term due to the hedged position of its portfolio. NRG transacts with a diversified pool of counterparties and actively manages the Company’s exposure to any single counterparty. See Part I, Item 2 – Liquidity and Capital Resources, and Part I, Item 3 – Quantitative and Qualitative Disclosures about Market Risk for further discussion.

Unsolicited Exelon Proposal

On October 19, 2008, the Company received an unsolicited proposal from Exelon Corporation to acquire all of the outstanding shares of the Company and on November 12, 2008, Exelon announced a tender offer for all of the Company’s outstanding common stock. On February 26, 2009, Exelon again extended the tender offer, to June 26, 2009. NRG’s Board of Directors, after carefully reviewing the proposal, unanimously concluded that the proposal was not in the best interests of the stockholders and has recommended that NRG stockholders not tender their shares. In addition, on March 17, 2009 Exelon filed a Preliminary Proxy Statement with the SEC with respect to their proposals for the Company’s 2009 Annual Meeting of Stockholders, which consists of: (i) consideration of Exelon’s four nominees as Class III directors, (ii) consideration of the expansion of NRG’s board to 19 directors, (iii) if the board expansion is approved, consideration of five additional Exelon nominees; and (iv) consideration of repealing any amendments to the NRG Bylaws after February 26, 2009. NRG’s Board of Directors has recommended a vote against each of the proposals.

Environmental Matters

Climate Change Update

On March 31, 2009, Representatives Henry Waxman and Edward Markey released draft climate change legislation, titled The American Clean Energy and Security Act of 2009. This comprehensive draft proposes a multi-sector, market based greenhouse gas cap and trade system starting in 2012 as well as national Renewable Energy Standards, expedited transmission planning and approval and aggressive efficiency measures. While the draft has provisions for both auction and allocation of the allowances, the level of allocation and the nature of recipients for such allocations have not been defined. The draft further exempts CO₂ from regulation under New Source Review, or NSR, as a criteria pollutant, or a hazardous air pollutant under the CAA. In 2008, NRG emitted 60 million metric tonnes of CO₂ in the US and will continue to provide input as a leading energy company and member of the US Climate Action Partnership, or USCAP, to achieve final legislation.

If the Waxman-Markey draft legislation or some other federal comprehensive climate change bill were to pass both House of Congress and be enacted into law, the actual impact on the Company’s financial performance would depend on a number of factors, including the overall level of GHG reductions required under any final legislation, the degree to which offsets may be used for compliance and their price and availability, and the extent to which NRG would be entitled to receive CO₂ emissions allowances without having to purchase them in an auction or on the open market. Thereafter, the impact would depend on the level of success of the Company’s multifold strategy, which includes (i) shaping public policy with the objective being constructive and effective federal GHG regulatory policy, and (ii) pursuing its RepoweringNRG and econrg programs. The Company’s multifold strategy is discussed in greater detail in Part I, Item 1 — Business, Carbon Update in NRG’s 2008 Annual Report on Form 10-K.

On April 17, 2009, the USEPA released a proposed endangerment finding that the mix of six key GHGs, including CO₂, threaten the public health and welfare. The proposed endangerment finding does not include any proposed regulations. This is in response to the Supreme Court’s decision in Massachusetts v. USEPA, which requires the USEPA to decide under the CAA’s mobile source title whether GHGs contribute to climate change, and if so, promulgate appropriate regulations. Absent eventual action from Congress on climate change, this finding could ultimately serve as a basis for rulemaking for stationary sources, like power plants, under the existing CAA.

Federal Environmental Initiatives

A number of regulations are under review by USEPA including CAIR, MACT, National Ambient Air Quality Standards, or NAAQS for ozone, small particle matter, or PM2.5, and the Phase II 316(b) Rule. These rules address air emissions and best practices for units with once-through-cooling. In addition, the USEPA has announced that it is considering new rules regarding the handling and disposition of coal combustion byproducts. While the Company cannot predict the requirements in the final versions nor the ultimate effect that the changing regulations will have on NRG’s business, NRG has prepared an environmental capital expenditure plan in anticipation of such requirements.

The Supreme Court released its decision in the Phase II 316(b) Rule case on April 1, 2009, that the USEPA does have the authority to allow a cost-benefit analysis in the evaluation of Best Technology Available, or BTA. This ruling is favorable for the industry and NRG as it improves the USEPA’s ability to include alternatives to closed-loop cooling in its redraft of the Phase II 316(b) Rules.

Regional Environmental Initiatives

Northeast Region — NRG operates electric generating units located in Connecticut, Delaware, Maryland, Massachusetts and New York which are subject to RGGI. The RGGI CO₂ cap-and-trade program went into effect on January 1, 2009. An allowance must be surrendered for every US ton of CO₂ emitted with true up for 2009-2011 occurring in 2012. NRG’s emissions under RGGI was on the order of 12 million tonnes in 2008, although 2009 year-to-date emissions are tracking lower than first quarter 2008.

Regulatory Matters

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

Northeast Region

PJM —On March 26, 2009, the FERC issued an order accepting in part and rejecting in part a December 12, 2008, PJM proposal to revise the design of the RPM capacity market, and a February 9, 2009, settlement agreement reached between PJM and various load interests. The revisions will take effect with the next RPM Base Residual Auction for planning year 2012/2013, which is scheduled to take place in May 2009. Several parties have requested rehearing of the March 26, 2009 order.

West Region

California – The CAISO Market Redesign and Technology Update, or MRTU, commenced April 1, 2009. Significant components of the MRTU include: (i) locational marginal pricing of energy; (ii) a more effective congestion management system; (iii) a day-ahead market; and (iv) an increase to the existing bid caps. NRG considers these market reforms to generally be a positive development for its assets in the region, but additional time is needed to assess the impact of MRTU.

Texas Region

On October 6, 2008, as part of its determination of Competitive Renewable Energy Zones, or CREZ, the Public Utility Commission of Texas, or PUCT, issued its final order approving a significant transmission expansion plan to provide for the delivery of approximately 18,500 MW of energy from the western region of Texas, primarily wind generation – approximately 2,300 miles of new 345 kV lines and 42 miles of new 138 kV lines. In January 2009, Texas Industrial Energy Consumers, a trade organization composed of large industrial customers, appealed PUCT’s CREZ plan in state district court, seeking reversal of the final order. On March 30, 2009, PUCT issued a final order designating the transmission utilities that plan to construct the various CREZ transmission component projects. A large number of separate transmission licensing proceedings will be required prior to construction of the CREZ facilities. If completed as currently approved, the transmission upgrades and associated wind generation could impact wholesale energy and ancillary service prices in ERCOT. As part of the normal ERCOT five-year planning process, transmission utilities are also planning other system improvements, 2,800 circuit miles of transmission and more than 17,000 MVA of autotransformer capacity, intended to support increasing power demand and to address transmission congestion.

Changes in Accounting Standards

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

Consolidated Results of Operations

The following table provides selected financial information for the Company:


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

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

Total operating revenues		1,658			1,302			27
Operating Costs and Expenses
Cost of operations (including risk management activities of $68 in 2009)		766			804			(5	)
Depreciation and amortization		169			161			5
General and administrative		95			75			27
Development costs		13			12			8

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

Operating income		615			250			146
Other Income/(Expense)
Equity in (losses)/earnings of unconsolidated affiliates		22			(4	)		N/A
Other income/(expense), net		(3	)		9			(133	)
Interest expense		(138	)		(156	)		(12	)

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

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

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

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

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

N/A — Not Applicable

Operating revenues, excluding risk management activities, decreased $210 million during the three months ended March 30, 2009, compared to the same period in 2008.

•

Energy revenue — decreased $38 million during the three months ended March 31, 2009, compared to the same period in 2008:

Texas — energy revenue increased by $48 million, with $90 million of this increase driven by higher energy prices, partially offset by $42 million of reduced generation. During both 2008 and 2009, the average realized merchant prices were higher than the average contract prices. A higher volume of MWh sold under the merchant market yielded a higher average realized energy price, even though the average realized merchant price decreased by 11%. In addition, the 22% increase in contract price further contributed to the rise in average energy prices. Coal plant generation decreased by 7% and gas plant generation decreased by 40%, partially offset by new generation from the recently constructed Elbow Creek wind farm. Coal plant generation was impacted by a 51% decrease in average natural gas prices, increased production costs, and increased wind generation which moved the coal units further up the bid stack.

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

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

•

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

	o		Texas — capacity revenue decreased by $71 million due to a lower proportion of baseload contracts which contained a capacity component.

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

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

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

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

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

Cost of Operations

Cost of operations, excluding risk management activities, decreased $106 million during the three months ended March 31, 2009, compared to the same period in 2008.

•

Cost of energy — decreased $117 million during the three months ended March 31, 2009, compared to the same period in 2008 due to:

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

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

	o		South Central — cost of energy increased $14 million due to an increase in purchased energy reflecting higher gas costs resulting from a higher proportion of generation sourced from region’s tolled facility and higher capacity payments on such tolled facility. The tolling arrangement in 2009 was for three months compared to one month in 2008.

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

•

Other operating costs — increased $11 million during the three months ended March 31, 2009, compared to the same period in 2008 due to increased operating and maintenance expenses.

Risk Management Activities

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


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

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

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

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

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


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

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

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

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

Depreciation and Amortization

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

General and Administrative Expenses

General and administrative expenses increased by $20 million for the three months ended March 31, 2009, compared to the same period in 2008. The increase is due to:

	•		Acquisition and integration costs — increased $12 million due to costs incurred related to the acquisition of Reliant Retail.

	•		Consultant costs — increased $5 million as a result of efforts related to Exelon’s exchange offer and proxy contest.

	•		Wage and benefits expense — increased $3 million.

Equity in Earnings of Unconsolidated Affiliates

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

Other Income/(Expense), Net

NRG’s other income/(expense) decreased by $12 million for the three months ended March 31, 2009, compared to the same period in 2008. The 2009 amount includes a $9 million mark-to-market unrealized loss on a forward contract for foreign currency executed to hedge the sale proceeds from the MIBRAG sale.

Interest Expense

NRG’s interest expense decreased by $18 million for the three months ended March 31, 2009, compared to the same period in 2008. This decrease was due to lower debt balance and lower interest rate on the unhedged portion of the Term Loan Facility and the fair value hedge of the Senior Notes. In addition there was a decrease of $4 million as a result of higher interest capitalized on RepoweringNRG projects under construction.

Income Tax Expense

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

For the three months ended March 31, 2009 and 2008, NRG’s overall effective tax rate on continuing operations was different than the statutory rate of 35% primarily due to state income taxes and an increase in valuation allowance as a result of capital losses generated in the quarter for which there are no projected capital gain or available tax planning strategies. In addition, for the three months ended March 31, 2008, NRG’s overall effective tax rate on continuing operations was impacted by a taxable dividend from foreign operations.

Income from Discontinued Operations, Net of Income Tax Expense

For the three months ended March 31, 2008, NRG recorded income from discontinued operations, net of income tax expense, of $4 million. NRG closed the sale of ITISA during the second quarter 2008.

Results of Operations — Regional Discussions

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

Texas

For a discussion of the business profile of the Company’s Texas operations, see pages 23-26 of NRG Energy, Inc.’s 2008 Annual Report on Form 10-K.

Selected income statement data


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

Operating Revenues
Energy revenue	$	594	$	546			9	%
Capacity revenue		47		118			(60	)
Risk management activities		263		(104	)		N/A
Contract amortization		15		63			(76	)
Other revenues		6		26			(77	)

Total operating revenues		925		649			43
Operating Costs and Expenses
Cost of energy (including risk management activities)		238		258			(8	)
Other operating expenses		168		164			2
Depreciation and amortization		117		113			4

Operating Income	$	402	$	114			253
MWh sold (in thousands)		10,239		11,031			(7	)
MWh generated (in thousands)		10,073		10,756			(6	)
Business Metrics
Average on-peak market power prices ($/MWh)		33.66		71.30			(53	)
Cooling Degree Days, or CDDs _(a)		126		74			70
CDD’s 30 year rolling average		94		95			(1	)
Heating Degree Days, or HDDs _(a)		903		1,053			(14	)
HDD’s 30 year rolling average		1,122		1,132			(1	)%

(a)

National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period.

Operating Income

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

	•		Risk management activities — an increase of $367 million was primarily due to $327 million in greater unrealized derivative gains and $40 million in greater realized gains on settled financial transactions. These changes reflect a reduction in forward power and gas prices during the first quarter 2009 and the recognition of previously deferred amounts due to the discontinuance of certain 2009 cash flow hedges on baseload plant generation due to lower forecasted generation.

	•		Energy revenues — increased by $48 million due to higher average energy prices despite the lower sales volume.

•

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

Operating Revenues

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

	•		Risk management activities — gains of $263 million were recognized for the three months ended March 31, 2009, compared to a $104 million loss in the same period in 2008. The $263 million gains included $225 million of unrealized mark-to-market gains and $38 million in settled gains, or financial income, compared to $102 million in unrealized derivative losses and $2 million of settled financial losses in the same period in 2008. The $225 million gain from economic hedges included a $110 million unrealized gain of previously deferred amounts in OCI due to discontinuance of certain 2009 trades resulting from lower than expected baseload plant generation and the remaining $115 million unrealized gain was attributable to an increase in value of forward sales and fuel due to lower power and gas prices.

	•		Energy revenues — increased $48 million due to:

	o		Energy Prices – increased by $90 million as the average realized merchant price was higher than the average contract price in both periods. Higher MWh sold under merchant market yielded a higher average energy price, even though the average realized merchant price decreased by 11%. The 22% increase in contract price further contributed to the average energy price increase.

	o		Generation - decreased by 6% contributing to a $42 million decrease in sales volume. This decrease was driven by a 7% or 524,000 MWh decrease in coal plant generation and a 40% or 290,000 MWh decrease in gas plant generation, offset by a 102,000 MWh increase from the recently constructed Elbow Creek wind farm, which was not in operation in the first quarter 2008. Coal plant generation was adversely affected by lower energy prices driven by a 51% decrease in average natural gas prices, increased production cost to generate with the start of NO_x rules contained in CAIR, and increased wind generation which shifted the coal unit’s position in the bid stack. These factors led to increased hours where the coal units were either uneconomic to dispatch or where it was more economical to participate in the ancillary markets as compared to energy markets.

	•		Capacity revenue — decreased by $71 million due to a lower proportion of baseload contracts which contain a capacity component.

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

	•		Other revenue — decreased by $20 million due to lower ancillary services as well as reduced allocation of physical sales and emissions credits sales.

Cost of Energy

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

	•		Natural gas costs — decreased by $48 million due to a 51% decline in average natural gas prices and a 40% decrease in gas-fired generation.

	•		Purchased energy — decreased by $14 million due to a $33 per MWh decrease in average price to procure energy from the market combined with 174,000 fewer MWhs purchased.

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

	•		Ancillary Service Costs — decreased by $11 million due to a decrease in purchased ancillary services costs incurred to meet contract obligations.

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

These decreases were offset by:

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

	•		Miscellaneous Cost of Energy — increased $9 million due to losses on settled financial transactions associated with oil transactions hedging price risk on rail transportation contracts.

Other Operating Expenses

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

Northeast Region

For a discussion of the business profile of the Northeast region, see pages 27-29 of NRG Energy, Inc.’s 2008 Annual Report on Form 10-K.

Selected income statement data


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

Operating Revenues
Energy revenue	$	181	$	264			(31	)%
Capacity revenue		96		110			(13	)
Risk management activities		182		(38	)		N/A
Other revenues		5		24			(79	)

Total operating revenues		464		360			29
Operating Costs and Expenses
Cost of energy (including risk management activities)		117		168			(30	)
Other operating expenses		94		93			1
Depreciation and amortization		29		26			12

Operating Income	$	224	$	73			207
MWh sold (in thousands)		2,637		3,591			(27	)
MWh generated (in thousands)		2,637		3,591			(27	)
Business Metrics
Average on-peak market power prices ($/MWh)_(b)		58.29		86.16			(32	)
Cooling Degree Days, or CDDs_(a)		—		—			—
CDD’s 30 year rolling average		—		—			—
Heating Degree Days, or HDDs_(a)		3,207		2,961			8
HDD’s 30 year rolling average		3,093		3,127			(1	)%

(a)		National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period.

(b)		MWh sold are shown net of MWh purchased to satisfy certain load contracts in the region.

Operating Income

Operating income increased by $151 million for the three months ended March 31, 2009, compared to the same period in 2008 due to:

	•		Operating revenues — increased by $104 million due to favorable impact of risk management activities, offset by lower energy, capacity and other revenues.

	•		Cost of energy – decreased by $51 million due to lower generation and fuel costs.

Operating Revenues

Operating revenues increased by $104 million for the three months ended March 31, 2009, compared to the same period in 2008, due to:

•

Risk management activities — gains of $182 million were recorded for the three months ending March 31, 2009, compared to losses of $38 million during the same period in 2008. The $182 million gain included $122 million of unrealized mark-to-market gains and $60 million in gains on settled transactions, or financial income, compared to $48 million in unrealized mark-to-market losses and $10 million in financial income during the same period in 2008. The $122 million unrealized gain included $107 million unrealized gain recognition of previously deferred amounts in OCI as a result of discontinuance of certain 2009 cash flow hedges on baseload plants generation due to lower forecasted generation.

•

Energy revenues — decreased by $83 million due to:

	o		Energy prices — decreased by $32 million reflecting an average 12% decline in merchant energy prices. This decrease was partially offset by higher net contract revenue of $11 million driven by lower net costs incurred in meeting obligations under load serving contracts in the PJM market.

	o		Generation — decreased by $63 million due to a 27% decrease in generation in 2009 compared to 2008, driven by a 26% decrease in coal generation and a 48% decrease in New York City gas generation. Coal generation in western New York declined 17% or 286,000 MWhs due to a 20 day planned outage in January 2009 for the baghouse equipment tie in work on one of the region’s generators combined with a transmission line outage starting in mid-March which limited the flow of power out of western New York thus depressing energy prices and creating reserve shut down hours for the region’s coal units. Coal generation at the Indian River facility declined 36% or 417,000 MWhs. Weakened demand for power combined with low gas prices resulted in node prices at the Indian River facility being under $55 per MWh for 63% of the available hours during the first quarter 2009 versus only 24% in the first quarter 2008. Lower prices combined with higher cost of production from the introduction of RGGI and NO_x rules contained in CAIR resulted in increased hours where the units were uneconomic to dispatch. The Somerset facility experienced similar weakened demand and low gas prices, with generation down 62% or 123,000 MWh. The decline in gas generation is largely attributable to fewer run hours for voltage support at the Arthur Kill facility.

•

Capacity revenues — decreased by $14 million due to:

	o		NYISO — capacity revenues decreased by $13 million due to unfavorable prices. The lower capacity market prices are a result of NYISO’s reductions in Installed Reserve Margins and ICAP in-city mitigation rules effective March 2008.

	o		PJM — capacity revenues decreased by $3 million due to lower capacity prices.

	o		NEPOOL — capacity revenues increased by $2 million due to higher volume of Locational Forward Reserve Market, or LFRM, revenues on the Cos Cob repowered unit which entered service in June 2008.

•

Other revenues — decreased by $19 million due to $10 million lower allocations of net physical gas sales and $7 million due to decreased activity in the trading of emission allowances.

Cost of Energy

Cost of energy decreased by $51 million for the three months ended March 31, 2009, compared to the same period in 2008, due to:

	•		Natural gas costs — decreased by $33 million due to lower gas generation and 38% lower average prices per MMBtu.

	•		Coal costs — decreased by $21 million, or 22%, due to 26% lower coal generation as discussed in energy revenues above.

	•		Fuel risk management activities — increased by $8 million due to increased mark-to-market losses on fuel hedges.

These decreases were offset by:

	•		Carbon emissions expense — increased by $5 million due to the January 1, 2009 implementation of RGGI and the recognition of carbon compliance cost under this program.

	•		Oil costs — increased by $4 million due to higher oil-fired generation as a result of a colder January 2009.

South Central Region

For a discussion of the business profile of the South Central region, see pages 29-31 of NRG Energy, Inc.’s 2008 Annual Report on Form 10-K.

Selected income statement data


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

Operating Revenues
Energy revenue	$	96		$	100		(4	)%
Capacity revenue		68			57		19
Risk management activities		(7	)		13		(154	)
Contract amortization		6			6		—
Other revenues		(1	)		3		(133	)

Total operating revenues		162			179		(9	)
Operating Costs and Expenses
Cost of energy (including risk management activities)		110			88		25
Other operating expenses		22			22		—
Depreciation and amortization		17			17		—

Operating Income	$	13		$	52		(75	)
MWh sold (in thousands)		3,169			3,088		3
MWh generated (in thousands)		2,706			3,024		(11	)
Business Metrics
Average on-peak market power prices ($/MWh)		37.30			67.73		(45	)
Cooling Degree Days, or CDDs_(a)		6			5		20
CDD’s 30 year rolling average		31			31		—
Heating Degree Days, or HDDs_(a)		1,805			1,885		(4	)
HDD’s 30 year rolling average		1,895			1,914		(1	)%

(a)

Operating income decreased by $39 million for the three months ended March 31, 2009, compared to the same period in 2008, primarily due to:

	•		Operating revenues — decreased by $17 million due to decreases in risk management activities, energy revenue, and other revenues. These decreases were offset by an increase in capacity revenue. Mild weather and lower merchant power prices contributed to the decrease.

	•		Cost of energy — increased by $22 million due to higher purchased energy costs reflecting increased use of the region’s tolled facilities.

Operating Revenues

Operating revenues decreased by $17 million for the three months ended March 31, 2009, compared to the same period in 2008, due to:

•

Risk Management Activities — losses of $7 million were recognized during the first quarter 2009 compared to gains of $13 million recognized during the same period in 2008. The $7 million loss included $20 million in unrealized losses offset by realized gains of $13 million compared to $9 million in unrealized gains and $4 million in realized gains for the same period in 2008. The $20 million unrealized loss was the net effect of a $6 million unrealized mark-to-market gain from trading activity and the reversal of $26 million of mark-to-market losses on trading activity.

	•		Energy revenues — decreased by $4 million due to a $15 million decline in contract revenue offset by an $11 million increase in merchant energy revenues. The decline in contract revenue reflected a $13 million drop due to the expiration of a contract with a regional utility and a $2 million decrease in cost pass through from the cooperatives. The expiration of the contract freed up energy to be sold into the merchant market, but at lower average prices. Increased use of the region’s tolled facility provided additional energy to the merchant market.

	•		Capacity revenues —capacity revenue increased by $11 million due to a $9 million increase from a new capacity agreement with a regional utility and a $3 million increase in capacity revenue from region’s Rockford plants which dispatch into the PJM market.

Cost of Energy

Cost of energy increased by $22 million for the three months ended March 31, 2009, compared to the same period in 2008, due to:

	•		Purchased energy — increased by $16 million reflecting higher fuel costs associated with an increase of 532,000 MWhs sourced from the region’s tolled facility and higher capacity payments on the tolled facility. The region’s tolling agreement covered three months in 2009 compared to one month in 2008.

	•		Fuel risk management activities — increased by $8 million and included $5 million in unrealized losses related to fuel transportation hedging activities and $3 million in realized losses associated with that same hedging activity.

This increase was offset by decreases in coal costs of $1 million and natural gas costs of $1 million, respectively:

	•		Coal costs — decreased by $1 million due to an 11% reduction in coal generation and a decrease in fuel transportation surcharges offset by a contractual increase in rail contract base rates.

	•		Natural gas costs — decreased by $1 million as a result of falling gas prices offset by a 50% increase in generation from the region’s gas peaking plants.

West Region

For a discussion of the business profile of the West region, see pages 31-33 of NRG Energy, Inc.’s 2008 Annual Report on Form 10-K.

Selected income statement data


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

Operating Revenues
Energy revenue	$	2		$	—		N/A
Capacity revenue		29			38		(24	)%
Risk management activities		(3	)		—		N/A
Other revenues		—			—		—

Total operating revenues		28			38		(26	)
Operating Costs and Expenses
Cost of energy (including risk management activities)		4			2		100
Other operating expenses		25			18		39
Depreciation and amortization		2			1		100

Operating Income	$	(3	)	$	17		(118	)
MWh sold (in thousands)		169			150		13
MWh generated (in thousands)		169			150		13
Business Metrics
Average on-peak market power prices ($/MWh)		40.46			80.30		(50	)
Cooling Degree Days, or CDDs_(a)		—			—		—
CDD’s 30 year rolling average		7			7		—
Heating Degree Days, or HDDs_(a)		1,410			1,525		(8	)
HDD’s 30 year rolling average		1,419			1,434		(1	)%

(a)

Operating Income

Operating income decreased by $20 million for the three months ended March 31, 2009, compared to the same period in 2008, due to:

	•		Capacity revenues — decreased by $9 million primarily due to expiration of a two year tolling agreement at the El Segundo facility in April 2008.

	•		Cost of energy — increased by $2 million due to a write down to market of fuel oil inventory no longer used in the production of energy

	•		Other operating expenses — increased by $7 million due to higher major maintenance expense of $5 million associated with the El Segundo Unit 4 and Encina facilities as well as normal maintenance expense of $2 million associated with planned outages.

Liquidity and Capital Resources

Liquidity Position

As of March 31, 2009, and December 31, 2008, NRG’s liquidity, excluding collateral received, was approximately $3.1 billion and $3.4 billion, respectively, comprised of the following:


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

Cash and cash equivalents	$	1,188		$	1,494
Funds deposited by counterparties		1,275			754
Restricted cash		17			16

Total cash		2,480			2,264
Synthetic Letter of Credit Facility availability		884			860
Revolver Credit Facility availability		1,000			1,000

Total liquidity		4,364			4,124
Less: Funds deposited as collateral by hedge counterparties		(1,277	)		(760	)

Total liquidity, excluding collateral received	$	3,087		$	3,364

For the three months ended March 31, 2009, total liquidity increased by $240 million due to a rise in funds deposited by $521 million and increased availability of the synthetic letter of credit by $24 million, offset by lower cash balances by $306 million. Changes in cash balances are further discussed hereinafter under Cash Flow Discussion. Cash and cash equivalents and funds deposited by counterparties at March 31, 2009, were predominantly held in money market funds invested in treasury securities, treasury repurchase agreements or government agency debt.

The line item “Funds deposited by counterparties” consist of cash collateral received from hedge counterparties in support of energy risk management activities, and it is the Company’s intention as of March 31, 2009 to limit the use of these funds. The change in these amounts was due to an increase of in-the-money positions as a result of decreasing forward prices. Depending on market fluctuation and the settlement of the underlying contracts, the Company will refund this collateral to the counterparties pursuant to the terms and conditions of the underlying trades. The Company’s balance sheet reflects a liability for cash collateral received within current liabilities.

Management believes that the Company’s liquidity position and cash flows from operations will be adequate to finance operating and maintenance capital expenditures, to fund dividends to NRG’s preferred shareholders, and other liquidity commitments. Management continues to regularly monitor the Company’s ability to finance the needs of its operating, financing and investing activity in a manner consistent with its intention to maintain a net debt to capital ratio in the range of 45-60%.

SOURCES OF FUNDS

The principal sources of liquidity for NRG’s future operating and capital expenditures are expected to be derived from new and existing financing arrangements, asset sales, existing cash on hand and cash flows from operations.

Financing Arrangements

Senior Credit Facility

As of March 31, 2009, NRG has a Senior Credit Facility which is comprised of a senior first priority secured term loan, or the Term Loan Facility, a $1.0 billion senior first priority secured revolving credit facility, or the Revolving Credit Facility, and a $1.3 billion senior first priority secured synthetic letter of credit facility, or the Synthetic Letter of Credit Facility. The Senior Credit Facility was last amended on June 8, 2007. As of March 31, 2009, NRG had issued $416 million of letters of credit under the Synthetic Letter of Credit Facility, leaving $884 million available for future issuances. Under the Revolving Credit Facility, as of March 31, 2009, NRG had not issued any letters of credit.

TANE Facility

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

Dunkirk Power LLC Tax-Exempt Bonds

On April 15, 2009, NRG executed a $59 million tax-exempt bond financing through its wholly owned subsidiary, Dunkirk Power LLC. The bonds were issued by the County of Chautauqua Industrial Development Agency and will be applied towards construction of emission control equipment on the Dunkirk Generating Station in Dunkirk, NY. The bonds initially bear weekly interest based on the SIFMA rate, have a maturity date of April 1, 2042, and are enhanced by a letter of credit under the Company’s Revolving Credit Facility covering amounts drawn on the facility. The initial proceeds were $31 million with the remaining balance being released over time as construction costs are paid.

GenConn Energy LLC related financings

On April 27, 2009, a wholly owned subsidiary of NRG closed on an EBL in the amount of $121.5 million from a syndicate of banks. The purpose of the EBL is to fund the Company’s proportionate share of the project construction costs required to be contributed into GenConn, a 50% equity method investment of the Company. The EBL, which is fully collateralized with a letter of credit issued under the Company’s Synthetic Letter of Credit Facility, will bear interest at a rate of LIBOR plus 2% on drawn amounts. The EBL will mature on the earlier of the commercial operations date of the Middletown project or July 26, 2011. The EBL also features a mandatory prepayment of the portion of the loan utilized for the Devon project (approximately $56 million) becoming due on the earlier of Devon’s commercial operations date or January 27, 2011. The initial proceeds of the EBL were $61 million and the remaining amounts will be drawn as necessary to fund construction costs.

At the same time, GenConn secured financing from the same syndicate of banks for 50% of its project construction costs through a seven-year term loan facility, as well as a five year revolving working capital loan and letter of credit facility, collectively the GenConn Facility. The aggregate credit amount secured under the GenConn Facility, which is non-recourse to NRG, was $291 million, including $48 million for the revolving facility. No amounts were immediately drawn under the GenConn Facility.

First and Second Lien Structure

NRG has granted first and second liens to certain counterparties on substantially all of the Company’s assets. NRG uses the first and second lien structure to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or MWh equivalents. To the extent that the underlying hedge positions for a counterparty are in-the-money to NRG, the counterparty would have no claim under the lien program. The lien program limits the volume that can be hedged, not the value of underlying out-of-the money positions. The first lien program does not require NRG to post collateral above any threshold amount of exposure. Within the first and second lien structure, the Company can hedge up to 80% of its baseload capacity and 10% of its non-baseload assets with these counterparties for the first 60 months and then declining thereafter. Net exposure to a counterparty on all trades must be positively correlated to the price of the relevant commodity for the first lien to be available to that counterparty. The first and second lien structure is not subject to unwind or termination upon a ratings downgrade of a counterparty or NRG and has no stated maturity date.

The Company’s lien counterparties may have a claim on the Company’s assets to the extent market prices exceed the hedged price. As of March 31, 2009, and April 23, 2009, there was no exposure to out-of-the-money positions to counterparties on hedges under either the first or second liens.

The following table summarizes the amount of MWs hedged against the Company’s baseload assets and as a percentage relative to the Company’s forecasted baseload capacity under the first and second lien structure as of April 23, 2009:


Equivalent Net Sales Secured by First and Second Lien Structure (a)	2009			2010			2011			2012			2013

In MW (b)		4,969			4,612			3,704			2,123			788
As a percentage of total forecasted baseload capacity (c)		71	%		68	%		55	%		31	%		12	%

(a)		Equivalent Net Sales include natural gas swaps converted using a weighted average heat rate by region.

(b)		2009 MW value consists of May through December positions only.

(c)		Forecasted baseload capacity under the first and second lien structure represents 80% of the total Company’s baseload assets.

Asset Sales

Disposition of MIBRAG Investment

On February 25, 2009, NRG entered into an agreement to sell its 50% ownership interest in Mibrag B.V. to a consortium of Severočeské doly Chomutov, a member of the CEZ Group, and J&T Group. Mibrag B.V.’s principal holding is MIBRAG which is jointly owned by the Company and URS Corporation. As part of the transaction, URS Corporation also has entered into an agreement to sell its 50% stake in MIBRAG. For its share, NRG expects to receive EUR202 million, subject to certain adjustments including transaction costs. The transaction is subject to customary closing conditions, including European Commission regulatory approvals and the absence of material adverse changes. The sale is expected to close during the second quarter of 2009.

USES OF FUNDS

The Company’s requirements for liquidity and capital resources, other than for operating its facilities, can generally be categorized by the following: (i) commercial operations activities; (ii) debt service obligations; (iii) capital expenditures including RepoweringNRG and environmental; and (iv) corporate financial transactions including return of capital to shareholders.

Commercial Operations

NRG’s commercial operations activities require a significant amount of liquidity and capital resources. These liquidity requirements are primarily driven by: (i) margin and collateral posted with counterparties; (ii) initial collateral required to establish trading relationships; (iii) timing of disbursements and receipts (i.e., buying fuel before receiving energy revenues); and (iv) initial collateral for large structured transactions. As of March 31, 2009, commercial operations had total cash collateral outstanding of $176 million, and $416 million outstanding in letters of credit to third parties primarily to support its economic hedging activities. As of March 31, 2009, total collateral held from counterparties was $1.3 billion and $34 million of letters of credit.

Future liquidity requirements may change based on the Company’s hedging activities and structures, fuel purchases, and future market conditions, including forward prices for energy and fuel and market volatility. In addition, liquidity requirements are dependent on NRG’s credit ratings and general perception of its creditworthiness.

Debt Service Obligations

NRG must annually offer a portion of its excess cash flow (as defined in the Senior Credit Facility) to its first lien lenders under the Term Loan Facility. The percentage of excess cash flow offered to these lenders is dependent upon the Company’s consolidated leverage ratio (as defined in the Senior Credit Facility) at the end of the preceding year. Of the amount offered, the first lien lenders must accept 50% while the remaining 50% may either be accepted or rejected at the lenders’ option. In March 2009, NRG made and the lenders accepted a repayment of approximately $197 million for the mandatory annual offer relating to 2008.

As of March 31, 2009, NRG had approximately $4.7 billion in aggregate principal amount of unsecured high yield notes or Senior Notes, had approximately $2.4 billion in principal amount outstanding under the Term Loan Facility, and had issued $416 million of letters of credit under the Company’s $1.3 billion Synthetic Letter of Credit Facility. The Revolving Credit Facility matures on February 2, 2011 and the Synthetic Letter of Credit Facility matures on February 1, 2013.

Capital Expenditures

For the three months ended March 31, 2009, the Company’s capital expenditures, including accruals, were approximately $186 million, of which $78 million was related to RepoweringNRG projects. The following table summarizes the Company’s capital expenditures for the three months ended March 31, 2009, and the estimated capital expenditure and repowering investments forecast for the remainder of 2009.


(In millions)	Maintenance			Environmental		Repowering		Total

Northeast	$	8		$	39	$	—	$	47
Texas		59					12		71
South Central		(1	)				—		(1	)
West		1			—		1		2
Wind development		—			—		28		28
Nuclear development		—			—		37		37
Other		2			—		—		2

Total	$	69		$	39	$	78	$	186

Estimated capital expenditures for the remainder of 2009	$	193		$	191	$	278	$	662

RepoweringNRG capital expenditures and investments — RepoweringNRG project capital expenditures consisted of approximately $28 million related to the Company’s Langford wind farm project which is currently under construction. In addition, the Company’s RepoweringNRG capital expenditures included $12 million for the construction of Cedar Bayou Unit 4 in Texas and $37 million for the development of STP Units 3 and 4 in Texas.

The Company’s estimated repowering capital expenditures for the remainder of 2009 are expected to be approximately $278 million. Of this amount, $157 million is estimated for STP units 3 and 4 without giving effect to any partner contributions or potential equity sell down, $13 million is anticipated for the construction of Cedar Bayou Unit 4, and the balance is anticipated for the construction of the Langford wind farm.

Major maintenance and environmental capital expenditures — The Company’s baghouse projects at western New York facilities resulted in environmental capital expenditures of $39 million for the three months ended March 31, 2009. Other capital expenditures included $25 million for STP fuel and $34 million in maintenance capital expenditures in Texas primarily related to the W.A. Parish and Limestone plants.

NRG anticipates funding its maintenance capital projects primarily with funds generated from operating activities. In addition, on April 16, 2009, the Company closed on an approximately $59 million tax-exempt bond financing through its Dunkirk Power LLC subsidiary, with the bonds issued by the County of Chautauqua Industrial Development Agency. These funds are expected to fund environmental capital expenditures at the Dunkirk Generating facility in 2009.

Loans to affiliates — As of March 31, 2009, the Company had funded approximately $44 million in loans to GenConn Energy LLC, a 50/50 joint venture vehicle of NRG and the United Illuminating Company as a part of the Devon and Middletown plant projects. These loans, which are in the form of an interest bearing note, mature in 2009, and will be fully repaid with the proceeds from the financing of GenConn. All future construction costs for GenConn Energy LLC will be funded from the equity bridge loans of NRG and the United Illuminating Company and non-recourse project level financing.

Environmental Capital Expenditures

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

Capital Allocation

In addition to the aforementioned planned investments in maintenance and environmental capital expenditures and RepoweringNRG in 2009, and the 2009 repayment of Term Loan Facility debt to the first lien lenders, the Company’s Capital Allocation Plan includes the completion of the 2008 Capital Allocation Plan with the planned purchase of $30 million of common stock as well as the purchase of an additional $300 million in common stock under the previously announced 2009 Capital Allocation Plan, with such purchases to be made from time to time at subject to market conditions and other factors, including as permitted by US securities laws.

Preferred Stock Dividend Payments

For the three months ended March 31, 2009, NRG paid approximately $6 million, $4 million, and $4 million in dividend payments to holders of the Company’s 5.75%, 4%, and 3.625% Preferred Stock. On March 16, 2009, the outstanding shares of the 5.75% Preferred Stock converted into common stock and, as a result, there will be no further dividends paid with respect to this series of preferred stock.

CSF Share Lending Arrangement

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

Benefit Plans Obligations

As of March 31, 2009, NRG contributed $6 million towards its three defined benefit pension plans to meet the Company’s 2009 benefit obligation. The Company’s expected contribution to the plans is $24 million during the remainder of 2009. The total 2009 planned contribution of $30 million is a decrease of $30 million from the expected contributions as disclosed in Part II, Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations, Liquidity and Capital Resources, in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008. This decrease in the 2009 expected contributions is due to the adoption by the Company in March 2009 of the new funding method options now available. The new methods were made allowable under new IRS guidance on the application of recent Congressional legislation on funding requirements.

Cash Flow Discussion

The following table reflects the changes in cash flows for the comparative years; all cash flow categories include the cash flows from both continuing operations and discontinued operations:


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

Net cash provided by operating activities	$	139		$	60		$	79
Net cash used by investing activities		(259	)		(132	)		(127	)
Net cash used by financing activities		(184	)		(224	)		40

Net Cash Provided By Operating Activities

For the three months ended March 31, 2009, net cash provided by operating activities increased by $79 million compared to the same period in 2008. The difference was due to:

	•		Collateral paid and option premiums collected — In 2009, the changes in collateral deposits paid and option premiums collected increased cash from operations by $177 million due to close out of commercial trade positions and lower commodity prices.

	•		Working capital — In 2009, the cash used by working capital items increased by $69 million, primarily as a result of higher inventory of $29 million and the balance due to other various changes in assets and liabilities.

Net Cash Used By Investing Activities

For the three months ended March 31, 2009, net cash used in investing activities was approximately $127 million more than the same period in 2008. This was due to:

	•		Capital expenditures — NRG’s capital expenditures increased by $69 million due to increased environmental capital expenditures which consists primarily of the Company’s baghouse projects in the Northeast.

	•		Trading of emission allowances — Net purchases and sales of emission allowances resulted in a decrease in cash of $57 million for 2009 as compared to 2008.

	•		Asset sales — The Company received $4 million in proceeds primarily from the sale of various assets in 2009 compared to proceeds of $12 million in proceeds primarily from the sale of rail cars in the same period in 2008 for a net decrease in cash of $8 million.

Net Cash Used By Financing Activities

For the three months ended March 31, 2009, net cash used by financing activities decreased by approximately $40 million compared to 2008, due to:

	•		Term Loan Facility debt payment — In 2009, the Company paid down $205 million of its Term Loan Facility, including the payment of excess cash flow, as discussed above under Debt Service Obligations. The Company paid down $151 million of its Term Loan Facility during 2008 for a net cash decrease of $54 million for the year ended 2009 compared to the same period in 2008.

	•		Share repurchase — During 2009, the Company did not repurchase any common stock during the first quarter in 2009, compared to $55 million for 2008.

	•		Receipt from/(Payment of) financing element of acquired derivatives — For 2009, the Company received approximately $40 million for the settlement of gas swaps related to the acquisition of Texas Genco in 2006 compared to a payment of approximately $1 million for 2008 for a net increase in cash of $41 million.

NOL’s, Deferred Tax Assets and FIN 48 Implications

As of March 31, 2009, the Company had generated total domestic pre-tax book income of $481 million and foreign continuing pre-tax book income of $15 million. In addition, NRG has cumulative foreign NOL carryforwards of $235 million, of which $47 million will expire starting in 2011 through 2018 and of which $188 million do not have an expiration date.

In addition to these amounts, the Company has $556 million of tax effected unrecognized tax benefits which relate primarily to net operating losses for tax return purposes but have been classified as capital loss carryforwards for financial statements purposes and for which a full valuation allowance has been established. As a result of the Company’s tax position, and based on current forecasts, the Company anticipates income tax payments of up to $100 million during 2009.

However, as the position remains uncertain, of the $556 million of tax effected unrecognized tax benefits, the Company has recorded a non-current tax liability of $272 million and may accrue the remaining balance as an increase to non-current liabilities until final resolution with the related taxing authority. The $272 million non-current tax liability for unrecognized tax benefits is due to taxable earnings for which there are no NOLs available to offset for financial statement purposes.

The Company continues to be under examination by the Internal Revenue Service.

New and On-going Company Initiatives

Reliant Retail Acquisition

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

Disposition of MIBRAG Investment

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

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

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

FORNRG Update

Beginning in January 2009, the Company transitioned to FORNRG 2.0 to target an incremental 100 basis point improvement to the Company’s ROIC by 2012. The initial targets for FORNRG 2.0 were based upon improvements in the Company’s ROIC as measured by increased cash flow. The economic goals of FORNRG 2.0 will focus on: (i) revenue enhancement, (ii) cost savings, and (iii) asset optimization, including reducing excess working capital and other assets. The FORNRG 2.0 program will measure its progress towards the FORNRG 2.0 goals by using the Company’s 2008 financial results as a baseline, while plant performance calculations will be based upon the appropriate historic baselines.

Nuclear Innovation North America

NINA is an NRG subsidiary focused on marketing, siting, developing, financing and investing in new advanced design nuclear projects in select markets across North America, including the planned STP units 3 and 4 that NRG is developing on a 50/50 basis with City of San Antonio’s agent City Public Service Board of San Antonio, or CPS Energy, at the STP nuclear power station site. TANE, a wholly owned subsidiary of Toshiba Corporation, owns a non-controlling interest in NINA.

The STP Expansion received a favorable preliminary ranking in the Department of Energy, or DOE, Loan Guarantee program and NINA submitted its part II application in mid-October. NRG believes DOE loan guarantee support is critical to new nuclear development projects. NINA is also actively pursuing additional loan guarantee options through the Japanese government and due diligence by Japanese financing agencies is in progress.

On February 24, 2009, NINA executed an EPC agreement with TANE to build the STP expansion. The EPC agreement is structured so as to assure that the new plant is constructed on time, on budget and to exacting standards. In accordance with the EPC agreement, TANE will provide engineering and development services prior to Full Notice to Proceed, or FNTP, on a time and materials basis. Upon the New Source Review’s, or NRC approval of the STP units 3 and 4 combined license and the owners decision to issue the FNTP, the EPC converts to a lump-sum turnkey contract with customary warranties, performance and schedule guarantees, and liquidated damage provisions. TANE’s obligations are backed by a guaranty from its ultimate parent, the Toshiba Corporation. Concurrent with the execution of the EPC agreement, NINA entered into a $500 million credit facility with TANE to finance the cost of material and equipment commitments prior to FNTP for STP units 3 and 4.

In light of the progress made by the project in terms of regulatory schedule, DOE loan guarantee process, and the conclusion of the EPC agreement, NINA has initiated a partial sell down process in the STP expansion. NINA has Memorandums of Understanding with a mix of investment grade rated load serving entities and industrial customers for all offtake from NINA’s anticipated 40% ownership interest in STP units 3 and 4’s generation. Currently, NINA and CPS Energy each own 50% of the 2,700 megawatt planned expansion of the South Texas Project nuclear facility. After the sell down, it is expected that each would own 40% and a new owner(s) would have a 20% equity interest although other ownership outcomes may arise. The ownership interests of STP units 1 and 2, (NRG 44%, CPS Energy 40% and Austin Energy 16%) are not affected by this proposed sale.

Agreement with eSolar

On February 23, 2009, the Company signed an agreement with eSolar, a leading provider of modular, scalable solar thermal power technology, to acquire the development rights to approximately 500MW of solar thermal power plants at sites in California and the Southwest. The first plant is anticipated to begin producing electricity as early as 2011.

At closing, NRG will invest in approximately $10 million for equity and associated development rights for three projects on sites in south central California and the Southwest US and a portfolio of PPAs to develop, build, own and operate up to 11 eSolar modular solar generating units at these sites. These development assets will use eSolar’s concentrating solar power, or CSP, technology to sell renewable electricity under contracted PPAs with local utilities.

RepoweringNRG Update

Currently, NRG has various projects in certain stages of development that includes a biomass project at Montville Generating Station and the repowering of Limestone 3, Big Cajun I and El Segundo sites. As a result of permitting delays related to on-going Natural Resource Defense Counsel claims, the El Segundo project will not reach its original completion date of June 1, 2011. The Company is contemplating certain PPA modifications, including commercial operations date.

The following is a summary of repowering projects that are under construction. In addition, NRG continues to participate in active bids in response to requests for proposals in markets in which it operates, particularly in the West and Northeast regions.

Plants under Construction

GenConn Energy LLC — In a procurement process conducted by the Department of Public Utility Control, or DPUC, and finalized in 2008, GenConn, a 50/50 joint venture of NRG and The United Illuminating Company, secured contracts in 2008 with Connecticut Light & Power, or CL&P, for the construction and operation of two 200 MW peaking facilities, at NRG’s Devon and Middletown sites in Connecticut. The contracts, which are structured as contracts for differences for the operation of the new power plants, have a 30-year term and call for commercial operation of the Devon project by June 1, 2010, and the Middletown project by June 1, 2011. GenConn has secured all state permits required for the projects and has entered into contracts for engineering, construction and procurement of the 8 GE LM6000 combustion turbines required for the projects. As of April 1 2009, construction has begun at the Devon site while construction at Middletown is expected to commence in the first quarter 2010.

Langford Wind Project — On March 12, 2009, NRG, through its wholly owned subsidiary, Padoma Wind Power LLC, began construction on a 150 MW wind farm located in Tom Green, Irion, and Schleicher Counties, Texas. The Langford Wind Project will utilize 100 General Electric 1.5 MW wind turbines. The project is scheduled to reach commercial operation by the end of 2009.

Off-Balance Sheet Arrangements

Obligations under Certain Guarantee Contracts

NRG and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include financial and performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. See Note 17, Guarantees, to this Form 10-Q for additional discussion.

Retained or Contingent Interests

NRG does not have any material retained or contingent interests in assets transferred to an unconsolidated entity.

Derivative Instrument Obligations

The Company’s 3.625% Preferred Stock includes a feature which is considered an embedded derivative per SFAS 133. Although it is considered an embedded derivative, it is exempt from derivative accounting as it is excluded from the scope pursuant to paragraph 11(a) of SFAS 133. As of March 31, 2009, based on the Company’s stock price, the embedded derivative was out-of-the-money and had no redemption value.

The Company’s unrestricted wholly-owned subsidiary, CSF II, has outstanding notes and preferred interests that contain a feature considered an embedded derivative per SFAS 133. Although it is considered a derivative, it is exempt from derivative accounting as it is excluded from the scope pursuant to paragraph 11(a) of SFAS 133. As of March 31, 2009, based on the Company’s stock price, the CSF II embedded derivative was out-of-the-money and had no redemption value.

Obligations Arising Out of a Variable Interest in an Unconsolidated Entity

Variable Interest in Equity Investments — As of March 31, 2009, NRG has several investments with an ownership interest percentage of 50% or less in energy and energy-related entities that are accounted for under the equity method of accounting. One of these investments, GenConn, is a variable interest entity for which NRG is not the primary beneficiary.

NRG’s pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $122 million as of March 31, 2009. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG.

Letter of Credit Facilities — The Company’s $1.3 billion Synthetic Letter of Credit Facility is unfunded by NRG and is secured by a $1.3 billion cash deposit at Deutsche Bank AG, New York Branch that was funded using proceeds from the Term Loan Facility investors who participated in the facility syndication. Under the Synthetic Letter of Credit Facility, NRG is allowed to issue letters of credit for general corporate purposes including posting collateral to support the Company’s commercial operations activities.

Contractual Obligations and Commercial Commitments

NRG has a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to the Company’s capital expenditure programs, as disclosed in the Company’s Form 10-K. Also see Note 14, Commitments and Contingencies, to the condensed consolidated financial statements of this Form 10-Q for a discussion of new commitments and contingencies that also include contractual obligations and commercial commitments that occurred during the first quarter 2009.

Critical Accounting Policies and Estimates

NRG’s discussion and analysis of the financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the US. The preparation of these financial statements and related disclosures in compliance with generally accepted accounting principles, or GAAP, requires the application of appropriate technical accounting rules and guidance as well as the use of estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges. These judgments, in and of themselves, could materially affect the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment may also have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies have not changed.

On an ongoing basis, NRG evaluates these estimates, utilizing historic experience, consultation with experts and other methods the Company considers reasonable. In any event, actual results may differ substantially from the Company’s estimates. Effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

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

ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

NRG is exposed to several market risks in the Company’s normal business activities. Market risk is the potential loss that may result from market changes associated with the Company’s merchant power generation or with an existing or forecasted financial or commodity transaction. The types of market risks the Company is exposed to are commodity price risk, interest rate risk and currency exchange risk. In order to manage these risks the Company uses various fixed-price forward purchase and sales contracts, futures and option contracts traded on the New York Mercantile Exchange, and swaps and options traded in the over-the-counter financial markets to:

	•		Manage and hedge fixed-price purchase and sales commitments;

	•		Manage and hedge exposure to variable rate debt obligations;

	•		Reduce exposure to the volatility of cash market prices; and

	•		Hedge fuel requirements for the Company’s generating facilities.

Commodity Price Risk

Commodity price risks result from exposures to changes in spot prices, forward prices, volatility in commodities, and correlations between various commodities, such as natural gas, electricity, coal, oil, and emissions credits. A number of factors influence the level and volatility of prices for energy commodities and related derivative products. These factors include:

	•		Seasonal, daily and hourly changes in demand;

	•		Extreme peak demands due to weather conditions;

	•		Available supply resources;

	•		Transportation availability and reliability within and between regions; and

	•		Changes in the nature and extent of federal and state regulations.

As part of NRG’s overall portfolio, NRG manages the commodity price risk of the Company’s merchant generation operations by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted sales of electricity and purchases of fuel. These instruments include forwards, futures, swaps, and option contracts traded on various exchanges, such as New York Mercantile Exchange, or NYMEX, Intercontinental Exchange, or ICE, and Chicago Climate Exchange, or CCX, as well as over-the-counter financial markets. The portion of forecasted transactions hedged may vary based upon management’s assessment of market, weather, operation and other factors.

While some of the contracts the Company uses to manage risk represent commodities or instruments for which prices are available from external sources, other commodities and certain contracts are not actively traded and are valued using other pricing sources and modeling techniques to determine expected future market prices, contract quantities, or both. NRG uses the Company’s best estimates to determine the fair value of commodity and derivative contracts held and sold. These estimates consider various factors, including closing exchange and over-the-counter price quotations, time value, volatility factors and credit exposure. However, it is likely that future market prices could vary from those used in recording mark-to-market derivative instrument valuation, and such variations could be material.

NRG measures the risk of the Company’s portfolio using several analytical methods, including sensitivity tests, scenario tests, stress tests, position reports, and Value at Risk, or VAR. VAR is a statistical model that attempts to predict risk of loss based on market price and volatility. Currently, the company estimates VAR using a Monte Carlo simulation based methodology. NRG’s total portfolio includes mark-to-market and non mark-to-market energy assets and liabilities.

NRG uses a diversified VAR model to calculate an estimate of the potential loss in the fair value of the Company’s energy assets and liabilities, which includes generation assets, load obligations, and bilateral physical and financial transactions. The key assumptions for the Company’s diversified model include: (i) a lognormal distribution of prices, (ii) one-day holding period, (iii) a 95% confidence interval, (iv) a rolling 36-month forward looking period, and (v) market implied volatilities and historical price correlations.

As of March 31, 2009, the VAR for NRG’s commodity portfolio, including generation assets, load obligations and bilateral physical and financial transactions calculated using the diversified VAR model was $35 million.

The following table summarizes average, maximum and minimum VAR for NRG for the three months ended March 31, 2009, and 2008:


(In millions)
VAR	2009		2008

As of March 31,	$	35	$	43
Average		41		53
Maximum		50		65
Minimum		34		35

Due to the inherent limitations of statistical measures such as VAR, the evolving nature of the competitive markets for electricity and related derivatives, and the seasonality of changes in market prices, the VAR calculation may not capture the full extent of commodity price exposure. As a result, actual changes in the fair value of mark-to-market energy assets and liabilities could differ from the calculated VAR, and such changes could have a material impact on the Company’s financial results.

In order to provide additional information for comparative purposes to NRG’s peers, the Company also uses VAR to estimate the potential loss of derivative financial instruments that are subject to mark-to-market accounting. These derivative instruments include transactions that were entered into for both asset management and trading purposes. The VAR for the derivative financial instruments calculated using the diversified VAR model as of March 31, 2009, for the entire term of these instruments entered into for both asset management and trading, was approximately $41 million primarily driven by asset-backed transactions.

Interest Rate Risk

NRG is exposed to fluctuations in interest rates through the Company’s issuance of fixed rate and variable rate debt. Exposures to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combination of the variable rate debt and the interest rate derivative instrument. NRG’s risk management policies allow the Company to reduce interest rate exposure from variable rate debt obligations.

As of March 31, 2009, the Company had various interest rate swap agreements with notional amounts totaling approximately $2.4 billion. If the swaps had been discontinued on March 31, 2009, the Company would have owed the counterparties approximately $141 million. Based on the investment grade rating of the counterparties, NRG believes its exposure to credit risk due to nonperformance by counterparties to its hedge contracts to be insignificant.

NRG has both long and short-term debt instruments that subject the Company to the risk of loss associated with movements in market interest rates. As of March 31, 2009, a 1% change in interest rates would result in a $11 million change in interest expense on a rolling twelve month basis.

As of March 31, 2009, the Company’s long-term debt fair value was $7.3 billion and the carrying amount was $7.8 billion. NRG estimates that a 1% decrease in market interest rates would have increased the fair value of the Company’s long-term debt by $386 million.

Liquidity Risk

Liquidity risk arises from the general funding needs of NRG’s activities and in the management of the Company’s assets and liabilities. NRG’s liquidity management framework is intended to maximize liquidity access and minimize funding costs. Through active liquidity management, the Company seeks to preserve stable, reliable and cost-effective sources of funding. This enables the Company to replace maturing obligations when due and fund assets at appropriate maturities and rates. To accomplish this task, management uses a variety of liquidity risk measures that take into consideration market conditions, prevailing interest rates, liquidity needs, and the desired maturity profile of liabilities.

Based on a sensitivity analysis, a $1 per MMBtu increase or decrease in natural gas prices across the term of the marginable contracts for power and gas positions would cause a change in margin collateral outstanding of approximately $72 million as of March 31, 2009. In addition, a 0.25 MMBtu/MWh change in heat rates for heat rate positions would result in a change in margin collateral of approximately $62 million as of March 31, 2009. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of March 31, 2009.

Under the second lien, NRG is required to post certain letters of credit as credit support for changes in commodity prices. As of March 31, 2009, no letters of credit are outstanding to second lien counterparties. With changes in commodity prices, the letters of credit could grow to $87 million, the cap under the agreements.

Credit Risk

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


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

Coal suppliers		2	%
Financial institutions		63
Utilities, energy, merchants, marketers and other		32
ISOs		3

Total		100	%


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

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

Total		100	%

(a)

Credit exposure excludes California tolling, uranium, coal transportation/railcar leases, New England Reliability Must-Run, cooperative load contracts and Texas Westmoreland coal contracts.

Fair Value of Derivative Instruments

NRG may enter into long-term power sales contracts, fuel purchase contracts and other energy-related financial instruments to mitigate variability in earnings due to fluctuations in spot market prices, to hedge fuel requirements at generation facilities and protect fuel inventories. In addition, in order to mitigate interest rate risk associated with the issuance of the Company’s variable rate and fixed rate debt, NRG enters into interest rate swap agreements.

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

The tables below disclose the activities that include both exchange and non-exchange traded contracts accounted for at fair value. Specifically, these tables disaggregate realized and unrealized changes in fair value; identify changes in fair value attributable to changes in valuation techniques; disaggregate estimated fair values at March 31, 2009, based on whether fair values are determined by quoted market prices or more subjective means; and indicate the maturities of contracts at March 31, 2009.


Derivative Activity Gains/(Losses)	(In millions)

Fair value of contracts as of December 31, 2008	$	996
Contracts realized or otherwise settled during the period		(249	)
Changes in fair value		843

Fair value of contracts as of March 31, 2009	$	1,590


	Fair Value of Contracts as of March 31, 2009
	Maturity						Maturity
(In millions)	Less Than		Maturity		Maturity		in Excess			Total Fair
Sources of Fair Value Gains/(Losses)	1 Year		1-3 Years		4-5 Years		4-5 Years			Value

Prices actively quoted	$	37	$	14	$	—	$	—		$	51
Prices provided by other external sources		735		442		273		(37	)		1,413
Prices provided by models and other valuation methods		90		23		13		—			126

Total	$	862	$	479	$	286	$	(37	)	$	1,590

A small portion of NRG’s contracts are exchange-traded contracts with readily available quoted market prices. The majority of NRG’s contracts are non exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter and on-line exchanges. For the majority of NRG markets, the Company receives quotes from multiple sources. To the extent that NRG receives multiple quotes, the Company’s prices reflect the average of the bid-ask mid-point prices obtained from all sources that NRG believes provide the most liquid market for the commodity. If the Company receives one quote then the mid point of the bid-ask spread for that quote is used. The terms for which such price information is available vary by commodity, region and product. The remainder of the assets and liabilities represent contracts for which external sources or observable market quotes are not available. These contracts are valued based on various valuation techniques including but not limited to internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Contracts valued with prices provided by models and other valuation techniques make up 8% of the total fair value of all derivative contracts. The fair value of each contract is discounted using a risk free interest rate. In addition, the Company applies a credit reserve to reflect credit risk which is calculated based on published default probabilities. To the extent that NRG’s net exposure under a specific master agreement is an asset, the Company is using the counterparty’s default swap rate. If the exposure under a specific master agreement is a liability, the Company is using NRG’s default swap rate. The credit reserve is added to the discounted fair value to reflect the exit price that a market participant would be willing to receive to assume NRG’s liabilities or that a market participant would be willing to pay for NRG’s assets. As of March 31, 2009, the credit reserve resulted in a $46 million decrease in fair value which is composed of a $23 million loss in OCI and a $23 million loss in derivative revenue and cost of operations.

The fair values in each category reflect the level of forward prices and volatility factors as of March 31, 2009, and may change as a result of changes in these factors. Management uses its best estimates to determine the fair value of commodity and derivative contracts NRG holds and sells. These estimates consider various factors including closing exchange 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.

The Company has elected to disclose derivative activity on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. Consequently, the magnitude of the changes in individual current and non-current derivative assets or liabilities is higher than the underlying credit and market risk of the Company’s portfolio. As discussed in Item 7A — Commodity Price Risk, NRG measures the sensitivity of the Company’s portfolio to potential changes in market prices using Value at Risk, or VAR, a statistical model which attempts to predict risk of loss based on market price and volatility. NRG’s risk management policy places a limit on one-day holding period VAR, which limits the Company’s net open position. As the Company’s trade-by-trade derivative accounting results in a gross-up of the Company’s derivative assets and liabilities, the net derivative assets and liability position is a better indicator of NRG’s hedging activity. As of March 31, 2009, NRG’s net derivative asset was $1.6 billion, an increase to total fair value of $594 million as compared to December 31, 2008. This increase was primarily driven by decreases in gas and power prices as well as the roll-off of trades that settled during the period.

Currency Exchange Risk

NRG may be subject to foreign currency risk as a result of the Company entering into purchase commitments with foreign vendors for the purchase of major equipment associated with RepoweringNRG initiatives. To reduce the risks to such foreign currency exposure, the Company may enter into transactions to hedge its foreign currency exposure using currency options and forward contracts. As of March 31, 2009, there were no foreign currency options and forward contracts outstanding for purchase commitments.

In addition, in connection with the MIBRAG sale, the Company entered into a foreign currency forward contract on March 12, 2009 to hedge the impact of exchange rate fluctuations on the sale proceeds. The foreign currency forward contract has a fixed exchange rate of 1.277. The contract requires NRG to pay EUR 200 million in exchange for $255 million on June 30, 2009.

As a result of the Company’s limited foreign currency exposure to date, the effect of foreign currency fluctuations has not been material to the Company’s results of operations, financial position and cash flows as of and for the three months ended March 31, 2009.

ITEM 4 — CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision and with the participation of NRG’s management, including its principal executive officer, principal financial officer and principal accounting officer, NRG conducted an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Based on this evaluation, the Company’s principal executive officer, principal financial officer and principal accounting officer concluded that the disclosure controls and procedures were effective as of the end of the period covered by this report on Form 10-Q.

Changes in Internal Controls over Financial Reporting

There were no changes in the Company’s internal controls over financial reporting (as such term is defined in Rules 13a-15(f) under the Exchange Act) that occurred in the first quarter of 2009 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Inherent Limitations over Internal Controls

NRG’s internal controls over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with generally accepted accounting principles. However, internal controls over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations, including the possibility of human error and circumvention by collusion or overriding of controls. Accordingly, even an effective internal control system may not prevent or detect material misstatements on a timely basis. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

PART II — OTHER INFORMATION

ITEM 1 — LEGAL PROCEEDINGS

For a discussion of material legal proceedings in which NRG was involved through March 31, 2009, see Note 14, Commitments and Contingencies, to the condensed consolidated financial statements of this Form 10-Q.

ITEM 1A — RISK FACTORS

In addition to the revised risk factor below, information regarding risk factors appears in Part I, Item 1A, Risk Factors in NRG Energy, Inc.’s 2008 Annual Report on Form 10-K for the fiscal year ended December 31, 2008.

If Exelon Corporation’s board expansion proposal is approved at NRG’s 2009 annual shareholders meeting and all of Exelon Corporation’s nominees are elected to NRG’s Board of Directors at the meeting, there will be an increased risk of a change of control under NRG’s debt instruments, and if that were to occur the Company could become obligated to immediately repay approximately $8 billion under the Senior Credit Facility and Senior Notes, which would likely have a material adverse affect on NRG’s business and financial condition and could render us insolvent.

Under NRG’s Senior Credit Facility and the indentures governing NRG’s Senior Notes, a “change of control” is deemed to occur if, among other triggering events, “a majority of the members of the Board of Directors of NRG are not continuing directors.” A “continuing director” is defined to mean, as of the date of determination, any director who was a member of NRG’s Board on the date of NRG’s Senior Credit Facility or the indenture governing NRG’s Senior Notes, as the case may be, or was nominated for election or elected to NRG’s Board with the approval of a majority of the “continuing directors” who were members of NRG’s Board at the time of such nomination or election. Based on NRG’s interpretation of this provision, the failure of a majority of NRG’s directors to qualify as “continuing directors” would result in a change of control. Since Exelon’s proposal, the NRG Board has added two members and currently consists of 14 members, all of whom qualify as “continuing directors.” If Exelon Corporation’s board expansion proposal passes and all of its nominees are elected to NRG’s Board, NRG’s Board would consist of 19 members, 10 of whom would be existing NRG directors who qualify as “continuing directors” and nine of whom would be directors nominated by Exelon Corporation who would not qualify as “continuing directors.” Therefore, under NRG’s interpretation of the change of control provision, a change of control would be triggered by any future event that reduces the number of continuing directors, such as the retirement or death of any such director. If a change of control were triggered under NRG’s Senior Credit Facility, an event of default would occur and the bank lenders under the facility would have the right to accelerate the outstanding indebtedness under the facility, which, as of March 31, 2009, totaled $2.4 billion, and if a change of control were triggered under the indentures governing NRG’s Senior Notes, note holders holding approximately $4.7 billion face amount of the notes would have the right to put the notes to the Company at 101% of par. If either or both of these events were to occur, it would likely have a material adverse impact on NRG’s business and financial condition and could render us insolvent. In addition to adding the two new Board members, the Company and the NRG Board may continue to explore other options to mitigate this risk.

ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3 — DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4 — SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

ITEM 5 — OTHER INFORMATION

None.

ITEM 6 — EXHIBITS


Exhibits

10.1*		LLC Membership Purchase Agreement between Reliant Energy, Inc. and NRG Retail LLC, dated as of February 28, 2009.

10.2		Credit Agreement by and among Nuclear Innovation North America LLC, Nuclear Innovation North America Investments LLC, NINA Texas 3 LLC and NINA Texas 4 LLC, as Borrowers and Toshiba America Nuclear Energy Corporation, as Administrative Agent and as Collateral Agent ⁽¹⁾

31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.

31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.

31.3		Certification of Chief Accounting Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.

32		Certification of Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, filed herewith.

*		Portions of this exhibit have been redacted and are subject to a confidential treatment request filed with the Securities and Exchange Commission pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended.
(1)		Incorporated herein by reference to NRG Energy Inc’s current report on Form 8-K filed on February 27, 2009.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	NRG ENERGY, INC. (Registrant)
	/s/ DAVID W. CRANE
	David W. Crane
	Chief Executive Officer (Principal Executive Officer)

	/s/ ROBERT C. FLEXON
	Robert C. Flexon
	Chief Financial Officer (Principal Financial Officer)

	/s/ JAMES J. INGOLDSBY
	James J. Ingoldsby
Date: April 30, 2009	Chief Accounting Officer (Principal Accounting Officer)

EXHIBIT INDEX


Exhibits

10.1*		LLC Membership Purchase Agreement between Reliant Energy, Inc. and NRG Retail LLC, dated as of February 28, 2009.

10.2		Credit Agreement by and among Nuclear Innovation North America LLC, Nuclear Innovation North America Investments LLC, NINA Texas 3 LLC and NINA Texas 4 LLC, as Borrowers and Toshiba America Nuclear Energy Corporation, as Administrative Agent and as Collateral Agent ⁽¹⁾

31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.

31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.

31.3		Certification of Chief Accounting Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.

32		Certification of Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, filed herewith.

*		Portions of this exhibit have been redacted and are subject to a confidential treatment request filed with the Securities and Exchange Commission pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended.
(1)		Incorporated herein by reference to NRG Energy Inc’s current report on Form 8-K filed on February 27, 2009.