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)

e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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


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

For the quarterly period ended: September 30, 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 shorter 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 þ 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 12b-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 Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.

Yes þ No o

As of October 28, 2009, there were 256,409,300 shares of common stock outstanding, par value $0.01 per share.

TABLE OF CONTENTS
Index


CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION			3
GLOSSARY OF TERMS			4
PART I — FINANCIAL INFORMATION			9
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES			9
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			61
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			110
ITEM 4 — CONTROLS AND PROCEDURES			115
PART II — OTHER INFORMATION			116
ITEM 1 — LEGAL PROCEEDINGS			116
ITEM 1A — RISK FACTORS			116
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			116
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES			116
ITEM 4 — SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS			116
ITEM 5 — OTHER INFORMATION			117
ITEM 6 — EXHIBITS			118
SIGNATURES			119
EX-10.1.A
EX-10.1.B
EX-31.1
EX-31.2
EX-31.3
EX-32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

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 of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or 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 Factors Related to NRG Energy, Inc. in Part I, Item 1A, of the Company’s Annual Report on Form 10-K, for the year ended December 31, 2008 and Risk Factors in Part II, Item 1A, of the Quarterly Report on Form 10-Q, for the quarters ended March 31, 2009 and June 30, 2009 including the following:

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

	•		Volatile power supply costs and demand for power;

	•		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 implement its FORNRG strategy of increasing the return on invested capital through operational performance improvements and a range of initiatives at plants and corporate offices to reduce costs or generate revenue;

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

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

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

ASC		The FASB Accounting Standards Codification, which the FASB has established as the source of authoritative U.S. GAAP

ASU		Accounting Standards Updates – updates to the ASC

Baseload capacity		Electric power generation capacity normally expected to serve loads on an around-the-clock basis throughout the calendar year

BACT		Best Available Control Technology

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

C&I		Commercial, industrial and governmental/institutional

CL&P		The Connecticut Light & Power Company

CO₂		Carbon dioxide

CREZ		Competitive Renewable Energy Zones

CS		Credit Suisse Group

CSF I		NRG Common Stock Finance I LLC

CSF II		NRG Common Stock Finance II LLC

CSF CAGRs		Embedded derivatives within the CSF debt, individually referred to as CSF I CAGR and CSF II CAGR

CSF Debt		CSF I and CSF II issued notes and preferred interest, individually referred to as CSF I Debt and CSF II Debt

CSRA		Credit Sleeve Reimbursement Agreement with Merrill Lynch in connection with acquisition of Reliant Energy, as hereinafter defined

DNREC		Delaware Department of Natural Resources and Environmental Control

DPUC		Department of Public Utility Control

EITF		Emerging Issues Task Force

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

FASB		Financial Accounting Standards Board

FERC		Federal Energy Regulatory Commission

FSP		FASB Staff Position

GHG		Greenhouse Gases


		GLOSSARY OF TERMS (continued)

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.

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

Licensing Board		Atomic Licensing and Safety Board

LTIP		Long-Term Incentive Plan

MACT		Maximum Achievable Control Technology

Mass		Residential and small business

MDPSC		Maryland Public Service Commission

Merit Order		A term used for the ranking of power stations in order of ascending marginal cost

MIBRAG		Mitteldeutsche Braunkohlengesellschaft mbH

MMBtu		Million British Thermal Units

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

Net Exposure		Counterparty credit exposure to NRG, net of collateral

NINA		Nuclear Innovation North America LLC

NOx		Nitrogen oxide

NOL		Net Operating Loss

NOV		Notice of Violation

NPNS		Normal Purchase Normal Sale

NRC		United States Nuclear Regulatory Commission

NSR		New Source Review

NYISO		New York Independent System Operator

OCI		Other Comprehensive Income

Phase II 316(b) Rule		A section of the Clean Water Act regulating cooling water intake structures

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


		GLOSSARY OF TERMS (continued)

PML		NRG Power Marketing, LLC, a wholly-owned subsidiary of NRG which procures transportation and fuel for the Company’s generation facilities, sells the power from these facilities, and manages all commodity trading and hedging for NRG

PPA		Power Purchase Agreement

PUCT		Public Utility Commission of Texas

Reliant Energy		NRG’s retail business in Texas purchased on May 1, 2009, from Reliant Energy, Inc. which is now known as RRI Energy, Inc., or RRI

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

REPS		Reliant Energy Power Supply, LLC

RERH		RERH Holding, LLC and its subsidiaries

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 Operator, or ISO

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

SIFMA		Securities Industry and Financial Markets Association

Senior Notes		The Company’s $5.4 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, $1.1 billion of 7.375% senior notes due 2017 and $700 million of 8.5% senior notes due 2019

SFAS		Statement of Financial Accounting Standards issued by the FASB

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 with TANE which matures on February 24, 2012

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

U.S.		United States of America

U.S. EPA		United States Environmental Protection Agency

U.S. GAAP		Accounting principles generally accepted in the United States

VaR		Value at Risk

WCP		WCP (Generation) Holdings, Inc.

ACCOUNTING PRONOUNCEMENTS

The following ASC topics are referenced in this report. In addition, certain U.S. GAAP standards and interpretations were adopted by the Company in 2009 prior to the July 1, 2009, effective date of the ASC, and were subsequently incorporated into one or more ASC topics. Further, certain U.S. GAAP standards were ratified by the FASB in 2009 prior to July 1, 2009, but are not yet effective and have therefore not yet been incorporated into the ASC. This glossary includes the definition of these “legacy” standards and interpretations under the ASC topic or topics which have been, or are expected to be, fully or partially incorporated.


ASC 105		ASC-105, Generally Accepted Accounting Principles; incorporates:

•

SFAS 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles


ASC 270		ASC-270, Interim Reporting; incorporates:

•

FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments


ASC 275		ASC-275, Risks and Uncertainties, incorporates:

•

FSP FAS 142-3, Determination of the Useful Life of Intangible Assets


ASC 320		ASC-320, Investments-Debt and Equity Securities; incorporates:

•

FSP FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments


ASC 323		ASC-323, Investments-Equity Method and Joint Ventures; incorporates:

•

EITF 08-6, Equity Method Investment Accounting Considerations


ASC 350		ASC-350, Intangibles-Goodwill and Others; incorporates:

•

FSP FAS 142-3, Determination of the Useful Life of Intangible Assets


ASC 450		ASC-450, Contingencies

ASC 470		ASC-470, Debt; incorporates:

•

FSP APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement)


ASC 715		ASC-715, Compensation-Retirement Benefits, incorporates:

•

FSP FAS 132 (R)-1, Employers’ Disclosures about Postretirement Benefit Plan Assets


ASC 718		ASC-718, Compensation-Stock Compensation; incorporates:

•

EITF 07-5, Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock


ASC 740		ASC-740, Income Taxes

ASC 805		ASC-805, Business Combinations; incorporates:

•

SFAS 141(R), Business Combinations

•

FSP FAS 141R-1, Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies


ASC 810		ASC-810, Consolidation; incorporates:

	•		SFAS 160, Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51, Consolidate Financial Statements

	Expected to incorporate SFAS 167, Amendments to FASB Interpretations No. 46 (R), effective January 1, 2010


ASC 815		ASC-815, Derivatives and Hedging; incorporates:

	•		SFAS 161, Disclosures About Derivative Instruments and Hedging Activities

	•		EITF 07-5, Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock


ASC 820		ASC-820, Fair Value Measurements and Disclosures; incorporates:


	•		FSP FAS 157-2, Effective Date of FASB Statement No. 157

	•		FSP 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


	•		EITF 08-5, Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement


ASC 825		ASC-825, Financial Instruments; incorporates:

•

FSP 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, Interim Disclosures about Fair Value of Financial Instruments


ASC 855		ASC-855, Subsequent Events; incorporates:

•

SFAS 165, Subsequent Events


ASU 2009-5		ASU 2009-5, Fair Value Measurement and Disclosures: Measuring Liabilities at Fair Value

ASU 2009-15		ASU 2009-15, Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing; incorporates:

•

EITF 09-1, Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing

PART I — FINANCIAL INFORMATION

ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES

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


	Three months ended September 30,						Nine months ended September 30,
(In millions, except for per share amounts)	2009			2008			2009			2008

Operating Revenues
Total operating revenues	$	2,916		$	2,612		$	6,811		$	5,230

Operating Costs and Expenses
Cost of operations		1,893			997			3,901			2,812
Depreciation and amortization		212			156			594			478
Selling, general and administrative		182			75			396			233
Acquisition-related transaction and integration costs		6			—			41			—
Development costs		12			13			34			29

Total operating costs and expenses		2,305			1,241			4,966			3,552
Operating Income		611			1,371			1,845			1,678

Other Income/(Expense)
Equity in earnings of unconsolidated affiliates		6			58			33			35
Gain on sale of equity method investment		—			—			128			—
Other income/(loss), net		5			(7	)		(9	)		14
Interest expense		(178	)		(142	)		(475	)		(442	)

Total other expense		(167	)		(91	)		(323	)		(393	)

Income From Continuing Operations Before Income Taxes		444			1,280			1,522			1,285
Income tax expense		166			502			614			503

Income From Continuing Operations		278			778			908			782
Income from discontinued operations, net of income taxes		—			—			—			172

Net Income		278			778			908			954
Less: Net loss attributable to noncontrolling interest		—			—			(1	)		—

Net income attributable to NRG Energy, Inc.		278			778			909			954

Dividends for preferred shares		6			13			27			41

Income Available for NRG Energy, Inc. Common Stockholders	$	272		$	765		$	882		$	913

Earnings per share attributable to NRG Energy, Inc.
Common Stockholders
Weighted average number of common shares outstanding — basic		249			235			247			236
Income from continuing operations per weighted average common share — basic	$	1.09		$	3.26		$	3.58		$	3.14
Income from discontinued operations per weighted average common share — basic		—			—			—			0.73

Net Income per Weighted Average Common Share — Basic	$	1.09		$	3.26		$	3.58		$	3.87

Weighted average number of common shares outstanding — diluted		272			277			274			278
Income from continuing operations per weighted average common share — diluted	$	1.02		$	2.81		$	3.29		$	2.79
Income from discontinued operations per weighted average common share — diluted		—			—			—			0.62

Net Income per Weighted Average Common Share — Diluted	$	1.02		$	2.81		$	3.29		$	3.41

Amounts attributable to NRG Energy, Inc.:
Income from continuing operations, net of income taxes	$	278		$	778		$	909		$	782
Income from discontinued operations, net of income taxes		—			—			—			172

Net Income	$	278		$	778		$	909		$	954

See notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS


	September 30, 2009			December 31, 2008
(In millions, except shares)	(unaudited)

ASSETS
Current Assets
Cash and cash equivalents	$	2,250		$	1,494
Funds deposited by counterparties		293			754
Restricted cash		26			16
Accounts receivable, less allowance for doubtful accounts of $40 and $3, respectively		1,119			464
Inventory		533			455
Derivative instruments valuation		3,199			4,600
Deferred income taxes		101			—
Cash collateral paid in support of energy risk management activities		475			494
Prepayments and other current assets		215			215

Total current assets		8,211			8,492

Property, plant and equipment, net of accumulated depreciation of $2,876 and $2,343, respectively		11,610			11,545

Other Assets
Equity investments in affiliates		392			490
Capital leases and note receivable, less current portion		507			435
Goodwill		1,718			1,718
Intangible assets, net of accumulated amortization of $483 and $335, respectively		1,942			815
Nuclear decommissioning trust fund		354			303
Derivative instruments valuation		1,039			885
Other non-current assets		181			125

Total other assets		6,133			4,771

Total Assets	$	25,954		$	24,808

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	537		$	464
Accounts payable		725			451
Derivative instruments valuation		3,017			3,981
Deferred income taxes		—			201
Cash collateral received in support of energy risk management activities		293			760
Accrued expenses and other current liabilities		636			724

Total current liabilities		5,208			6,581

Other Liabilities
Long-term debt and capital leases		8,229			7,697
Nuclear decommissioning reserve		296			284
Nuclear decommissioning trust liability		249			218
Deferred income taxes		1,572			1,190
Derivative instruments valuation		859			508
Out-of-market contracts		324			291
Other non-current liabilities		1,138			669

Total non-current liabilities		12,667			10,857

Total Liabilities		17,875			17,438

3.625% convertible perpetual preferred stock		247			247
Commitments and Contingencies
Stockholders’ Equity
Preferred stock		406			853
Common stock		3			3
Additional paid-in capital		4,568			4,350
Retained earnings		3,305			2,423
Less treasury stock, at cost — 26,080,051 and 29,242,483 shares, respectively		(782	)		(823	)
Accumulated other comprehensive income		320			310
Noncontrolling interest		12			7

Total Stockholders’ Equity		7,832			7,123

Total Liabilities and Stockholders’ Equity	$	25,954		$	24,808

See notes to condensed consolidated financial statements.

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


(In millions)
Nine months ended September 30,	2009			2008

Cash Flows from Operating Activities
Net income	$	908		$	954
Adjustments to reconcile net income to net cash provided by operating activities:
Distributions and equity in earnings of unconsolidated affiliates		(33	)		(24	)
Depreciation and amortization		594			478
Provision for bad debts		37			—
Amortization of nuclear fuel		28			31
Amortization of financing costs and debt discount/premiums		35			28
Amortization of intangibles and out-of-market contracts		79			(226	)
Changes in deferred income taxes and liability for unrecognized tax benefits		561			439
Changes in nuclear decommissioning trust liability		19			8
Changes in derivatives		(234	)		(144	)
Changes in collateral deposits supporting energy risk management activities		13			(320	)
Loss on sale of assets		2			13
Gain on sale of equity method investment		(128	)		—
Gain on sale of discontinued operations		—			(273	)
Gain on sale of emission allowances		(8	)		(52	)
Gain recognized on settlement of pre-existing relationship		(31	)		—
Amortization of unearned equity compensation		20			21
Changes in option premiums collected		(278	)		203
Cash used by changes in other working capital		(304	)		(50	)

Net Cash Provided by Operating Activities		1,280			1,086

Cash Flows from Investing Activities
Acquisition of Reliant Energy, net of cash acquired		(356	)		—
Capital expenditures		(560	)		(649	)
Increase in restricted cash, net		(10	)		(3	)
(Increase)/decrease in notes receivable		(18	)		20
Purchases of emission allowances		(68	)		(6	)
Proceeds from sale of emission allowances		20			75
Investments in nuclear decommissioning trust fund securities		(237	)		(441	)
Proceeds from sales of nuclear decommissioning trust fund securities		218			434
Proceeds from sale of discontinued operations, net of cash divested		—			241
Proceeds from sale of assets, net		6			14
Proceeds from sale of equity method investment		284			—
Equity investment in unconsolidated affiliate		—			(17	)
Other investments		(6	)		—

Net Cash Used by Investing Activities		(727	)		(332	)

Cash Flows from Financing Activities
Payment of dividends to preferred stockholders		(27	)		(41	)
Net payments to settle acquired derivatives that include financing elements		(140	)		(49	)
Payment to settle CSF I CAGR		—			(45	)
Payment for treasury stock		(250	)		(185	)
Proceeds from issuance of common stock, net of issuance costs		1			8
Installment proceeds from sale of noncontrolling interest in subsidiary		50			50
Proceeds from issuance of long-term debt		843			20
Payment of deferred debt issuance costs		(29	)		(2	)
Payments for short and long-term debt		(248	)		(202	)

Net Cash Provided by/(Used by) Financing Activities		200			(446	)

Change in cash from discontinued operations		—			43
Effect of exchange rate changes on cash and cash equivalents		3			—

Net Increase in Cash and Cash Equivalents		756			351
Cash and Cash Equivalents at Beginning of Period		1,494			1,132

Cash and Cash Equivalents at End of Period	$	2,250		$	1,483

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 primarily a wholesale power generation company with a significant presence in major competitive power markets in the United States, as well as a major retail electricity franchise in the ERCOT (Texas) market. NRG is engaged in the ownership, development, construction and operation of power generation facilities, the transacting in and trading of fuel and transportation services, the trading of energy, capacity and related products in the United States and select international markets, and supply of electricity and energy services to retail electricity customers in the Texas market.

The accompanying unaudited interim condensed consolidated financial statements have been prepared in accordance with the U.S. Securities and Exchange Commission’s, or SEC’s, regulations for interim financial information and with the instructions to Form 10-Q. Accordingly, they do not include all of the information and notes required by generally accepted accounting principles for complete financial statements. The following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to the Company’s financial statements in its Annual Report on Form 10-K for the year ended December 31, 2008. Interim results are not necessarily indicative of results for a full year.

In the opinion of management, the accompanying unaudited interim condensed consolidated financial statements contain all material adjustments consisting of normal and recurring accruals necessary to present fairly the Company’s consolidated financial position as of September 30, 2009, the results of operations for the three and nine months ended September 30, 2009, and 2008, and cash flows for the nine months ended September 30, 2009, and 2008. These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through November 2, 2009, the date the financial statements were issued.

Certain prior-year amounts have been reclassified for comparative purposes. In addition, as disclosed in Note 27, Unaudited Quarterly Financial Data, to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, the results of operations for the three months ended September 30, 2008, have been revised to reflect the correction of a $78 million overstatement of revenues from an error in the accounting for energy options. The effect of the revision on the three and nine months ended September 30, 2008 from the Company’s previously filed Form 10-Q, as adjusted for the effect of the adoption of FSP APB 14-1 (as discussed in Note 2, Summary of Significant Accounting Policies), is summarized as follows:


(In millions, except per share amounts)	Adjustment

Increase/(decrease):
Operating revenues	$	(78	)
Operating income		(78	)
Income tax expense		28
Income/(losses) from continuing operations, net of income taxes		(50	)
Net income attributable to NRG Energy, Inc.	$	(50	)
Income/(losses) from continuing operations per weighted average common share — basic	$	(0.21	)
Net income per weighted average common share — basic	$	(0.21	)
Income/(losses) from continuing operations per weighted average common share — diluted	$	(0.18	)
Net income per weighted average common share — diluted	$	(0.18	)

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.

Note 2 — Summary of Significant Accounting Policies

Cash and Cash Equivalents

Cash and cash equivalents at September 30, 2009, were predominantly held in money market funds invested in treasury securities, treasury repurchase agreements or government agency debt.

Other Cash Flow Information

NRG’s investing activities do not include non-cash capital expenditures of $43 million which were accrued at September 30, 2009.

Recent Accounting Developments

SFAS 168 — In June 2009, the Financial Accounting Standards Board, or FASB, issued SFAS No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, or SFAS 168. Effective July 1, 2009, this guidance establishes the FASB Accounting Standards Codification, or ASC, as the source of authoritative U.S. GAAP recognized by the FASB to be applied by nongovernmental entities. In addition, SFAS 168 also specifies that rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative U.S. GAAP for SEC registrants. All guidance contained in the ASC carries an equal level of authority. The Company adopted SFAS 168 for the quarterly reporting period ending September 30, 2009. SFAS 168 has been incorporated into the ASC as ASC-105, Generally Accepted Accounting Principles, or ASC 105.

Certain U.S. GAAP standards and interpretations were adopted by the Company in 2009 prior to the July 1, 2009, effective date of the ASC, and were subsequently incorporated into one or more ASC topics. Further, certain U.S. GAAP standards were ratified by the FASB in 2009 prior to July 1, 2009, but are not yet effective and have therefore not yet been incorporated into the ASC. This report retains the original title of these standards and interpretations, and references the ASC topic or topics which have been, or are expected to be, incorporated.

SFAS 141R — 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. As discussed in Note 4, Business Acquisition, to this Form 10-Q, on May 1, 2009, NRG acquired all of the Texas electric retail business operations, or Reliant Energy, of Reliant Energy, Inc., now known as RRI Energy, Inc., or RRI. The Company has applied the provisions of SFAS 141R to the Reliant Energy acquisition. As discussed further in Note 13, Income Taxes, any reductions after January 1, 2009, to existing net deferred tax assets or valuation allowances or changes to uncertain tax benefits, as they relate to Fresh Start or previously completed acquisitions, will be recorded to income tax expense rather than additional paid-in capital or goodwill. SFAS 141R has been incorporated into ASC-805, Business Combinations, or ASC 805.

FSP FAS 141R-1 — 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 has applied the provisions of FSP FAS 141R-1 to the Reliant Energy acquisition. The provisions of FSP FAS 141R-1 have been incorporated into ASC 805.

SFAS 160 — 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. SFAS 160 establishes 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. SFAS 160 has been incorporated into ASC-810, Consolidation, or ASC 810.

FSP APB 14-1 — 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) 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. The provisions of FSP APB 14-1 have been incorporated into ASC-470, Debt, or ASC 470, and ASC-825, Financial Instruments, or ASC 825.

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 embedded derivatives, or CSF CAGRs, 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 CSF CAGRs are accounted for under the guidance in ASC 470. Upon adoption of FSP APB 14-1, the fair value of the CSF CAGRs 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. In addition, in August 2008 the Company paid $45 million to CS for the benefit of CSF I to early settle the CSF CAGR in the Company’s CSF I notes and preferred interests, which was reclassified from interest expense to Additional Paid-In Capital upon the adoption of FSP APB 14-1.

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						Nine months ended
	September 30,						September 30,
(In millions, except per share amounts)	2009			2008			2009			2008

Increase/(decrease):
Interest Expense	$	2		$	(44	)	$	5		$	(39	)
Income From Continuing Operations		(2	)		44			(5	)		39
Net Income attributable to NRG Energy, Inc.		(2	)		44			(5	)		39
Basic Earnings Per Share	$	(0.01	)	$	0.19		$	(0.02	)	$	0.16
Diluted Earnings Per Share	$	—		$	0.16		$	(0.02	)	$	0.14

FSP FAS 157-4 — 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 ASC-820, Fair Value Measurements and Disclosure, or ASC 820, when the volume and level of activity for the asset or liability have significantly decreased, includes guidance on identifying circumstances that indicate a transaction is not orderly, and requires disclosures about inputs and valuation techniques used to measure fair value. 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 is applied prospectively. The Company’s adoption of FSP FAS 157-4 beginning with the interim reporting period ended June 30, 2009, did not have a material impact on the Company’s results of operations, financial position, or cash flows. The provisions of FSP FAS 157-4 have been incorporated into ASC 820.

FSP FAS 107-1 and APB 28-1 — 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 requires disclosures about fair value of financial instruments for interim and annual reporting periods of publicly traded companies ending after the FSP’s effective date of June 15, 2009. The Company’s adoption of FSP FAS 107-1 and APB 28-1 beginning with the interim period ended June 30, 2009, did not have an impact on the Company’s results of operations, financial position, or cash flows. The provisions of FSP FAS 107-1 and APB 28-1 have been incorporated in ASC-270, Interim Reporting, or ASC 270, and ASC-825, Financial Instruments, or ASC 825.

FSP FAS 115-2 and FAS 124-2 — 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 U.S. 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, and its disclosure requirements apply only to periods ending after the FSP’s effective date. The Company’s adoption of FSP FAS 115-2 and FAS 124-2 beginning with the interim period ended June 30, 2009, did not have an impact on the Company’s results of operations, financial position, or cash flows. The provisions of FSP FAS 115-2 and FAS 124-2 have been incorporated in ASC-320, Investments — Debt and Equity Securities, or ASC 320.

SFAS 165 — In May 2009, the FASB issued SFAS No. 165, Subsequent Events, or SFAS 165. SFAS 165 incorporates the accounting and disclosure requirements related to subsequent events found in auditing standards into U.S. GAAP, effectively making management directly responsible for subsequent events accounting and disclosures. SFAS 165 also requires disclosure of the date through which subsequent events have been evaluated. SFAS 165 is effective for interim and annual reporting periods ending after June 15, 2009, and shall be applied prospectively. The Company’s adoption of SFAS 165 beginning with the interim period ended June 30, 2009, did not have an impact on the Company’s results of operations, financial position, or cash flows. SFAS 165 has been incorporated in ASC-855, Subsequent Events, or ASC 855.

SFAS 167 — In June 2009, the FASB issued SFAS No. 167, Amendments to FASB Interpretation No. 46(R), or SFAS 167. This guidance amends FIN 46(R) by altering how a company determines when an entity that is insufficiently capitalized or not controlled through voting should be consolidated. SFAS 167 is effective at the start of the first fiscal year beginning after November 15, 2009. The Company is presently evaluating the impact of SFAS 167 on its results of operations, financial position, and cash flows. SFAS 167 is expected be incorporated into ASC 810 upon its effective date.

ASU 2009-15/EITF 09-1 — In July 2009, the FASB ratified EITF Issue No. 09-1, Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing, or EITF 09-1. This Issue applies to equity-classified share lending arrangements on an entity’s own shares, when executed in contemplation of a convertible debt offering or other financing. EITF 09-1 addresses how to account for the share-lending arrangement and the effect, if any, that the loaned shares have on earnings-per-share calculations. The share lending arrangement is required to be measured at fair value and recognized as an issuance cost associated with the convertible debt offering or other financing. Earnings-per-share calculations would not be affected by the loaned shares unless the share borrower defaults on the arrangement and does not return the shares. If counterparty default is probable, the share lender is required to recognize an expense equal to the then fair value of the unreturned shares, net of the fair value of probable recoveries. The Company will apply EITF 09-1 for share lending agreements entered into after June 15, 2009, and will apply EITF 09-1 on a retrospective basis for arrangements outstanding as of January 1, 2010. NRG is currently evaluating the impact of this statement upon its adoption on the Company’s results of operations, financial position and cash flows. In October 2009, the FASB issued Accounting Standards Update, or ASU No. 2009-15, Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing, or ASU 2009-15, which formally incorporated the provisions of EITF 09-1 into ASC 470.

ASU 2009-5 — In August 2009, the FASB issued ASU No. 2009-05, Fair Value Measurement and Disclosures: Measuring Liabilities at Fair Value, or ASU 2009-5. This ASU, which amends ASC 820 and ASC 825, provides clarification on measuring liabilities at fair value when a quoted price in an active market is not available. The Company’s adoption of ASU 2009-5 beginning with the interim period ended September 30, 2009, did not have an impact on the Company’s results of operations, financial position or cash flows.

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

	•		FSP No. FAS 142-3, Determination of the Useful Life of Intangible Assets, which has been incorporated in ASC-275, Risks and Uncertainties, or ASC 275, and ASC-350, Intangibles — Goodwill and Other, or ASC 350.

	•		FSP No. FAS 157-2, Effective Date of FASB Statement No. 157, which has been incorporated in ASC 820.

	•		SFAS No. 161, Disclosures About Derivative Instruments and Hedging Activities, which has been incorporated in ASC-815, Derivatives and Hedging, or ASC 815.

	•		FSP No. FAS 132(R)-1, Employers’ Disclosures about Postretirement Benefit Plan Assets, which has been incorporated in ASC-715, Compensation–Retirement Benefits, or ASC 715.

	•		EITF No. 07-5, Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock, which has been incorporated in ASC 718, Compensation-Equity Compensation, or ASC 718, and ASC 815.

	•		EITF No. 08-5, Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement, which has been incorporated in ASC 820.

	•		EITF No. 08-6, Equity Method Investment Accounting Considerations, which has been incorporated in ASC-323, Investments-Equity Method and Joint Ventures, or ASC 323.

Note 3 — Comprehensive Income/(Loss)

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


	Three months ended						Nine months ended
	September 30,						September 30,
(In millions)	2009			2008			2009			2008

Net income	$	278		$	778		$	908		$	954

Changes in derivative activity		(73	)		1,112			(9	)		112
Foreign currency translation adjustment		20			(104	)		38			(69	)
Reclassification adjustment for translation loss/(gain) realized upon sale of foreign investments		—			—			(22	)		15
Unrealized gain/(loss) on available-for-sale securities		1			(4	)		3			(1	)

Other comprehensive income/(loss)		(52	)		1,004			10			57
Comprehensive income attributable to noncontrolling interest		—			—			1			—

Comprehensive income attributable to NRG Energy, Inc.	$	226		$	1,782		$	919		$	1,011

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		(9	)
Foreign currency translation adjustment		38
Reclassification adjustment for translation gain realized upon sale of foreign investment		(22	)
Unrealized gain on available-for-sale securities		3

Accumulated other comprehensive income as of September 30, 2009	$	320

Note 4 — Business Acquisition

General

On May 1, 2009, NRG, through its wholly-owned subsidiary NRG Retail LLC, acquired Reliant Energy, which consisted of the entire Texas electric retail business operations of RRI, including the exclusive use of the trade name “Reliant.” Reliant Energy arranges for the transmission and delivery of electricity to customers, bills customers, collects payments for electricity sold and maintains call centers to provide customer service. Reliant Energy is the second largest electricity provider to residential and small business, or Mass, customers in Texas, with approximately 1.6 million Mass customers as of September 30, 2009. Reliant Energy also sells electricity and energy services to commercial, industrial and governmental/institutional customers, or C&I, customers in Texas with approximately 0.1 million C&I customers, based on metered locations as of September 30, 2009. These customers include refineries, chemical plants, manufacturing facilities, hospitals, universities, government agencies, restaurants, and other facilities.

With its complementary generation portfolio, the Texas region is a supplier of power to Reliant Energy, thereby creating the potential for a more stable, reliable and competitive business that benefits Texas consumers. By backing Reliant Energy’s load-serving requirements with NRG’s generation and risk management practices, the need to sell and buy power from other financial institutions and intermediaries that trade in the ERCOT market may be reduced, resulting in reduced transaction costs and credit exposures. This combination of generation and retail allows for a reduction in actual and contingent collateral, initially through offsetting transactions and over time by reducing the need to hedge the retail power supply through third parties, thus reducing collateral postings. In addition, with Reliant Energy’s base of retail customers, NRG now has a customer interface with the scale that is important to the successful deployment of new distributed generation and retail alternative energy technologies.

Credit Support

On May 1, 2009, NRG arranged with Merrill Lynch Commodities, Inc. and certain of its affiliates, or Merrill Lynch, the former credit provider of RRI Energy, Inc., or RRI, to provide continuing credit support to Reliant Energy after closing the acquisition. In connection with entering into a transitional credit sleeve facility, or CSRA, NRG contributed $200 million of cash to Reliant Energy. In conjunction with the CSRA, NRG Power Marketing LLC, or PML, and Reliant Energy Power Supply LLC, or REPS, wholly-owned subsidiaries of NRG, modified or novated certain transactions with counterparties to transfer PML’s in-the-money transactions to REPS and moved $522 million of cash collateral held by NRG to Merrill Lynch, thereby reducing Merrill Lynch’s actual and contingent collateral supporting Reliant Energy out-of-money positions. At September 30, 2009, these trades with counterparties were still open, thus there was no impact on NRG’s consolidated financial statements, and NRG continued to record unrealized and realized gains/losses for these novated trades in its Texas and Northeast segments. The monthly fee for the CSRA was 5.875% on an annualized basis of the predetermined exposure.

Additionally, on May 1, 2009, NRG entered into a $50 million working capital facility with Merrill Lynch in connection with the acquisition of Reliant Energy. The facility required that the Company comply with all terms of the CSRA. NRG initially drew $25 million under the facility. These funds accrued interest at the prime rate.

Reliant Energy conducts its business through RERH Holdings, LLC and subsidiaries, or RERH, Reliant Energy Texas Retail, LLC, and Reliant Energy Services Texas, LLC. Through October 5, 2009, the obligations of Reliant Energy under the CSRA were secured by first liens on substantially all of the assets of RERH, and the obligations of RERH under the CSRA were non-recourse to NRG and its other non-pledgor subsidiaries. The CSRA agreement (a) restricted the ability of RERH to, among other actions, (i) encumber its assets; (ii) sell certain assets; (iii) incur additional debt; (iv) pay dividends or pay subordinated debt; (v) make investments or acquisitions; or (vi) enter into certain transactions with affiliates and (b) required NRG to manage risks related to commodity prices. RERH was designed to maintain the separate nature of its assets in order to ensure that such assets are available first and foremost to satisfy the entities’ creditor claims. At September 30, 2009, the cash balance at RERH was $322 million.

Effective October 5, 2009, as discussed in Note 20, Subsequent Event, to this Form 10-Q, the Company executed the CSRA Amendment resulting in the removal of the associated first liens and the termination of the $50 million working capital facility with Merrill Lynch.

Acquisition method of accounting

The acquisition of Reliant Energy is accounted for under the acquisition method of accounting in accordance with ASC-805. Accordingly, NRG has conducted an assessment of net assets acquired and has recognized provisional amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition are expensed as incurred. The initial accounting for the business combination is not complete because the appraisals necessary to assess the fair values of the net assets acquired and the amount of goodwill (if any) to be recognized are still in process, and the Company is also in the process of valuing the tax basis of the net assets acquired, which will affect the deferred tax balances. The provisional amounts recognized are subject to revision until the appraisals are completed and to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date. Any changes to the fair value assessments and the tax basis values will affect the final balance of goodwill.

NRG paid RRI $287.5 million in cash at closing, funded from NRG’s cash on hand. NRG also made payments to RRI of $63 million on June 15, 2009, and $11 million on July 24, 2009, as initial remittances of acquired net working capital. In addition, the Company expects to remit approximately $9 million of acquired net working capital to RRI in the fourth quarter of 2009, bringing the total cash consideration to approximately $370 million. NRG also recognized a $31 million non-cash gain on the settlement of a pre-existing relationship, representing the in-the-money value to NRG of an agreement that permits Reliant Energy to call on certain NRG gas plants when necessary for Reliant Energy to meet its load obligations. NRG has recorded this gain within “Operating Revenues” in its condensed consolidated statement of operations. This non-cash gain is considered a component of consideration in accordance with ASC 805, and together with cash consideration, brings total consideration to approximately $401 million.

The following table summarizes the provisional values assigned to the net assets acquired, including cash acquired of $6 million, as of the acquisition date:


(In millions)

Assets
Current and non-current assets	$	635
Property, plant and equipment		72
Intangible assets subject to amortization:
In-market customer contracts		790
Customer relationships		399
Trade names		178
In-market energy supply contracts		54
Other		6
Derivative assets		1,942
Deferred tax asset, net		14
Goodwill		—

Total assets acquired		4,090

Liabilities
Current and non-current liabilities		550
Derivative liabilities		2,996
Out-of-market energy supply and customer contracts		143

Total liabilities assumed		3,689

Net assets acquired	$	401

No goodwill is expected to be deductible for tax purposes.

Current assets include accounts receivable with a preliminary fair value of $569 million and gross contractual amounts of $589 million at the time of acquisition. The Company expects to collect the fair value of the contractual cash flows; any difference between fair value and the amount collected will be an adjustment to the acquired working capital payment due to RRI.

The Company, through its acquisition of Reliant Energy, is subject to material contingencies relating to Excess Mitigation Credits (see Note 15, Commitments and Contingencies, to this Form 10-Q) and Retail Replacement Reserve (see Note 16, Regulatory Matters, to this Form 10-Q). Due to the number of variables and assumptions involved in assessing the possible outcome of these matters, sufficient information does not exist to reasonably estimate the fair value of these contingent liabilities. These material contingencies have been evaluated in accordance with ASC-450, Contingencies, or ASC 450, and related guidance, and no provisional amounts for these matters have been recorded at the acquisition date. In addition, NRG provided certain indemnities in connection with the acquisition. See Note 18, Guarantees, to this Form 10-Q for further discussion.

Measurement period adjustments

The following measurement period adjustments to the provisional amounts, attributable to refinement of the underlying appraisal assumptions, were recognized during the quarter ended September 30, 2009:


(In millions)	Increase/(Decrease)

Assets
Intangible assets subject to amortization:
In-market customer contracts	$	57
Customer relationships		(82	)
In-market energy supply contracts		17
Deferred tax asset, net		3

Total assets acquired		(5	)

Liabilities
Out-of-market energy supply and customer contracts		(5	)

Total liabilities assumed		(5	)

Net assets acquired	$	—

Fair value measurements

The provisional fair values of the intangible assets/liabilities and property, plant and equipment at the acquisition date were measured primarily based on significant inputs that are not observable in the market and thus represent a Level 3 measurement as defined in ASC 820. Significant inputs were as follows:

	•		Customer contracts — The fair values of the customer contracts, representing those with Reliant Energy’s C&I customers, were estimated based on the present value of the above/below market cash flows attributable to the contracts based on contract type, discounted utilizing a current market interest rate consistent with the overall credit quality of the portfolio. The fair values also accounted for Reliant Energy’s historical costs to acquire customers. The above/below market cash flows were estimated by comparing the expected cash flows to be generated based on existing contracted prices and expected volumes with the cash flows from estimated current market contract prices for the same expected volumes. The estimated current market contract prices were derived considering current market costs, such as price of energy, transmission and distribution costs, and miscellaneous fees, plus a normal profit margin. The customer contracts are amortized to revenues, over a weighted average amortization period of five years, based on expected volumes to be delivered for the portfolio.

	•		Customer relationships — The customer relationships, reflective of Reliant Energy’s Mass customer base, were valued using a variation of the income approach. Under this approach, the Company estimated the present value of expected future cash flows resulting from the existing customer relationships, considering attrition and charges for contributory assets (such as net working capital, fixed assets, software, workforce and trade names) utilized in the business, discounted at an independent power producer peer group’s weighted average cost of capital. The customer relationships are amortized to depreciation and amortization, over a weighted average amortization period of eight years, based on the expected discounted future net cash flows by year.

	•		Trade names — The trade names were valued using a “relief from royalty” method, an approach under which fair value is estimated to be the present value of royalties saved because NRG owns the intangible asset and therefore does not have to pay a royalty for its use. The trade names were valued in two parts based on Reliant Energy’s two primary customer segments — Mass customers and C&I customers. The avoided royalty revenues were discounted at an independent power producer peer group’s weighted average cost of capital. The remaining useful life of the trade names was determined by considering various factors, such as turnover and name changes in the independent power producer and utility industries, the current age of the Reliant brand, management’s intent to continue using the name at the current time, and feedback from external consultants regarding their experience with similar trade names. The trade names are amortized to depreciation and amortization, on a straight-line basis, over 15 years.

	•		Energy supply contracts — The fair values of the in-market and out-of-market energy supply contracts were determined in accordance with ASC 820. These contracts are amortized over periods ranging through 2016, based on the expected delivery under the respective contracts.

•

Property, plant and equipment — The fair value of property, plant and equipment was valued using a cost approach, which estimates value by determining the current cost of replacing an asset with another of equivalent economic utility. The cost to replace a given asset reflects the estimated reproduction or replacement cost for the property, less an allowance for loss in value due to depreciation.

The fair values of derivative assets and liabilities as of the acquisition date were determined in accordance with ASC 820. The breakdown of Level 1, 2 and 3 is as follows:


	Fair Value
(In millions)	Level 1		Level 2		Level 3		Total

Derivative assets	$	534	$	1,375	$	33	$	1,942

Derivative liabilities	$	534	$	2,357	$	105	$	2,996

Amortization of acquired intangible assets and out-of-market contracts

The following table presents the estimated remaining amortization related to the acquired intangible assets, for periods subsequent to September 30, 2009 and through 2014:


Year Ended December 31,	Customer		Customer		Trade		Energy Supply
(In millions)	Contracts		Relationships		Names		Contracts

2009 (three months)	$	99	$	44	$	3	$	—
2010		225		81		12		3
2011		152		57		12		4
2012		104		44		12		5
2013		49		31		12		6
2014		—		24		12		6

The following table presents the estimated amortization related to the acquired out-of-market contracts for 2009 — 2014:


	Energy Supply
Year Ended December 31,	and Customer
(In millions)	Contracts

2009 (three months)	$	23
2010		48
2011		18
2012		7
2013		3
2014		—

These amortization tables reflect the measurement period adjustments recognized during the quarter ended September 30, 2009.

Supplemental Pro Forma Information

Since the acquisition date, Reliant Energy contributed $2,965 million of operating revenues and $807 million in net income attributable to NRG.

The following supplemental pro forma information represents the results of operations as if NRG and Reliant Energy had combined at the beginning of the respective reporting periods:


	Three months ended September 30,					Nine months ended September 30,
(In millions, except per share amounts)	2009		2008			2009		2008

Operating revenues	$	2,911	$	5,122		$	8,625	$	11,633
Net income/(loss) attributable to NRG Energy, Inc.		282		(322	)		878		245
Earnings per share attributable to NRG common stockholders:
Basic	$	1.11	$	(1.43	)	$	3.45	$	1.60
Diluted	$	1.04	$	(1.43	)	$	3.17	$	1.49

The supplemental pro forma information has been adjusted to include the pro forma impact of amortization of intangible assets and out-of-market contracts, and depreciation of property, plant and equipment, based on the preliminary purchase price allocations. The pro forma data has also been adjusted to eliminate the non-recurring transaction costs incurred by NRG. Transactions between NRG and Reliant Energy have not been eliminated. The pro forma results are presented for illustrative purposes only and do not reflect the realization of potential cost savings, or any related integration costs. Certain cost savings may result from the acquisition, however, there can be no assurance that these cost savings will be achieved.

Significant Accounting Policies

The following pertains to Reliant Energy, in addition to NRG’s significant accounting policies referred to in Note 2, Summary of Significant Accounting Policies, to this Form 10-Q:

	•		Revenues — Gross revenues for energy sales and services to Mass customers and to C&I customers are recognized upon delivery under the accrual method. Energy sales and services that have been delivered but not billed by period end are estimated. Gross revenues also includes energy revenues from resales of purchased power, which were $151 million for the period ended September 30, 2009. These revenues represent a sale of excess supply to third parties in the market.

			As of September 30, 2009, Reliant Energy recorded unbilled revenues of $321 million for energy sales and services. Accrued unbilled revenues are based on Reliant Energy’s estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Volume estimates are based on daily forecasted volumes and estimated customer usage by class. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class. Estimated amounts are adjusted when actual usage is known and billed.

	•		Cost of Energy — Reliant Energy records cost of energy for electricity sales and services to retail customers based on estimated supply volumes for the applicable reporting period. A portion of its cost of energy ($68 million as of September 30, 2009) consisted of estimated transmission and distribution charges not yet billed by the transmission and distribution utilities. In estimating supply volumes, Reliant Energy considers the effects of historical customer volumes, weather factors and usage by customer class. Reliant Energy estimates its transmission and distribution delivery fees using the same method that it uses for electricity sales and services to retail customers. In addition, Reliant Energy estimates ERCOT ISO fees based on historical trends, estimates supply volumes and initial ERCOT ISO settlements. Volume estimates are then multiplied by the supply rate and recorded as cost of operations in the applicable reporting period.

	•		Allowance for Doubtful Accounts — Reliant Energy accrues an allowance for doubtful accounts based on estimates of uncollectible revenues by analyzing counterparty credit ratings (for commercial and industrial customers), historical collections, accounts receivable aging and other factors. Reliant Energy writes-off accounts receivable balances against the allowance for doubtful accounts when it determines a receivable is uncollectible.

	•		Gross Receipts Taxes — Reliant Energy records gross receipts taxes on a gross basis in revenues and cost of operations in its condensed consolidated statements of operations. During the period ended September 30, 2009, Reliant Energy’s revenues and cost of operations included gross receipts taxes of $39 million.

	•		Sales Taxes — Reliant Energy records sales taxes collected from its taxable customers and remitted to the various governmental entities on a net basis, thus, there is no impact on the Company’s condensed consolidated statement of operations.

Note 5 — Investments Accounted for by the Equity Method

MIBRAG — On June 10, 2009, NRG completed the sale of its 50% ownership interest in Mibrag B.V. to a consortium of Severoćeské 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 entered into an agreement to sell its 50% stake in MIBRAG.

For its share, NRG received EUR 203 million ($284 million at an exchange rate of 1.40 U.S.$/EUR), net of transaction costs. During the nine months ended September 30, 2009, NRG recognized an after-tax gain of $128 million. Prior to completion of the sale, NRG continued 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 to hedge the impact of exchange rate fluctuations on the sale proceeds. The foreign currency forward contract had a fixed exchange rate of 1.277 and required NRG to deliver EUR 200 million in exchange for $255 million on June 15, 2009. For the nine months ended September 30, 2009, NRG recorded an exchange loss of $24 million on the contract within “Other income/(loss), net.”

NRG provided certain indemnities in connection with its share of the transaction. See Note 18, Guarantees, to this Form 10-Q for further discussion.

Note 6 — Fair Value of Financial Instruments

The estimated carrying values and fair values of NRG’s recorded financial instruments are as follows:


	Carrying Amount				Fair Value
	September 30,		December 31,		September 30,		December 31,
	2009		2008		2009		2008
	(In millions)
Cash and cash equivalents	$	2,250	$	1,494	$	2,250	$	1,494
Funds deposited by counterparties		293		754		293		754
Restricted cash		26		16		26		16
Cash collateral paid in support of energy risk management activities		475		494		475		494
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities		8		7		8		7
Marketable equity securities		4		2		4		2
Trust fund investments		356		305		356		305
Notes receivable		214		156		221		166
Derivative assets		4,238		5,485		4,238		5,485
Long-term debt, including current portion		8,636		8,019		8,422		7,475
Cash collateral received in support of energy risk management activities		293		760		293		760
Derivative liabilities		3,876		4,489		3,876		4,489

Recurring Fair Value Measurements

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 September 30, 2009	Level 1		Level 2		Level 3		Total

Cash and cash equivalents	$	2,250	$	—	$	—	$	2,250
Funds deposited by counterparties		293		—		—		293
Restricted cash		26		—		—		26
Cash collateral paid in support of energy risk management activities		475		—		—		475
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities		—		—		8		8
Marketable equity securities		4		—		—		4
Trust fund investments		203		113		40		356
Derivative assets		964		3,171		103		4,238

Total assets	$	4,215	$	3,284	$	151	$	7,650

Cash collateral received in support of energy risk management activities	$	293	$	—	$	—	$	293
Derivative liabilities		956		2,747		173		3,876

Total liabilities	$	1,249	$	2,747	$	173	$	4,169

The following table reconciles the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements using significant unobservable inputs:


	Fair Value Measurement Using Significant Unobservable Inputs
	(Level 3)
(In millions)			Trust Fund
Nine months ended September 30, 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		1		—		(110	)		(109	)
Included in nuclear decommissioning obligations		—		8		—			8
Purchases/(sales), net		—		1		(3	)		(2	)
Transfers out of Level 3		—		—		(6	)		(6	)

Ending balance as of September 30, 2009	$	8	$	40	$	(70	)	$	(22	)

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 September 30, 2009	$	—	$	—	$	3		$	3

Realized and unrealized gains and losses included in earnings that are related to the 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 September 30, 2009, the credit reserve resulted in a $18 million increase in fair value which is composed of a $4 million gain in other comprehensive income, or OCI, and a $14 million gain in operating 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 2008 Annual Report on Form 10-K.

See Note 7, Accounting for Derivative Instruments and Hedging Activities, to this Form 10-Q for discussion regarding concentration of credit risk.

Note 7 — Accounting for Derivative Instruments and Hedging Activities

ASC 815 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 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 ASC 815, certain derivative instruments may qualify for the NPNS exception and are therefore exempt from fair value accounting treatment. ASC 815 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 and retail business, some of NRG’s commercial activities qualify for hedge accounting under the requirements of ASC 815. In order for the generation assets to 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. Most of the retail load contracts either qualify for the NPNS exception or fail to meet the criteria for a derivative and the majority of the supply contracts are recorded under mark-to-market accounting. 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 wholesale and retail 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 or purchase 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 purchase or sell a commodity.

	•		Weather and hurricane derivative products used to mitigate a portion of Reliant Energy’s lost revenue due to weather.

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 Reliant Energy’s 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 competitive wholesale supply and retail operations.

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 September 30, 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, excluding those derivatives that qualified for the NPNS exception as of September 30, 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 as
		of September 30, 2009
Commodity	Units	(In millions)

Emissions	Short Ton		1
Coal	Short Ton		60
Natural Gas	MMBtu		(582	)
Power^(a)	MWH		(27	)
Interest	Dollars	$	3,306


(a)		Power volumes include capacity sales.

Fair Value of Derivative Instruments

The following table summarizes the fair value within the derivative instrument valuation on the balance sheet as of September 30, 2009:


	Fair Value
(In millions)	Derivatives Asset		Derivatives Liability

Derivatives Designated as Cash Flow or Fair Value Hedges:
Interest rate contracts current	$	—	$	4
Interest rate contracts long term		9		123
Commodity contracts current		278		13
Commodity contracts long term		378		30

Total Derivatives Designated as Cash Flow or Fair Value Hedges		665		170

Derivatives Not Designated as Cash Flow or Fair Value Hedges:
Commodity contracts current		2,921		3,000
Commodity contracts long term		652		706

Total Derivatives Not Designated as Cash Flow or Fair Value Hedges		3,573		3,706

Total Derivatives	$	4,238	$	3,876

Impact of Derivative Instruments on the Statement of Operations

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


Amount of gain/(loss) recognized	Three months ended			Nine months ended
(In millions)	September 30, 2009			September 30, 2009

Derivative	$	3		$	(5	)
Senior Notes (hedged item)	$	(3	)	$	5

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

Location of

Amount of

Location of

Amount of

gain/(loss)

recognized in

recognized in OCI

reclassified from

income

(In millions)

(effective portion)

Accumulated

(ineffective

Three months ended September 30, 2009

after tax

OCI into Income

portion)

Interest rate contracts

)

Interest expense

—

Interest expense

Commodity contracts

(71

)

Operating revenue

Total

(73

)

Location of

Amount of

Location of

Amount of

gain/(loss)

recognized in

recognized in OCI

reclassified from

income

Income

(In millions)

(effective portion)

Accumulated

(ineffective

Nine months ended September 30, 2009

after tax

OCI into Income

portion)

Portion)

Interest rate contracts

Interest expense

—

Interest expense

Commodity contracts

(32

)

Operating revenue

398

Operating revenue

Total

)

398

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 operations for derivatives	Three months ended			Nine months ended
(In millions)	September 30, 2009			September 30, 2009

Location of gain/(loss) recognized in income for derivatives:
Operating revenue	$	(233	)	$	(117	)
Cost of operations	$	203		$	476

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. 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 collateral required for out-of-the-money positions and net accounts payable for contracts that have adequate assurance clauses that are in a net liability position as of September 30, 2009, was $163 million. The collateral required for out-of-the-money positions and net accounts payable for contracts with credit rating contingent features that are in a net liability position as of September 30, 2009, was $31 million. The Company is also a party to certain marginable agreements where NRG has a net liability position but the counterparty has not called for the collateral due, which is approximately $24 million as of September 30, 2009.

Under the CSRA, Merrill Lynch provided guarantees and the posting of collateral to the Company’s counterparties in supply transactions for the Company’s retail energy business. As of September 30, 2009, Merrill Lynch was providing $163 million in credit support to various counterparties (includes cash collateral posted by counterparties and Reliant Energy as an offset to exposure).

As described in Note 20, Subsequent Event, to this Form 10-Q, pursuant to the CSRA Amendment, effective October 5, 2009, the Company was required to post collateral for any net liability derivatives and other static margin associated with supply for Reliant Energy. In connection with the CSRA Amendment, the Company posted $366 million of cash collateral to Merrill Lynch and other counterparties, returned $53 million of counterparty collateral, issued letters of credit of $206 million, and received $45 million of counterparty collateral.

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.

Since the credit crisis began in late 2008, NRG has taken several additional steps to mitigate credit risk including the use of netting arrangements, entering contracts with collateral thresholds, setting volumetric limits with certain counterparties and restricting trading relationships with counterparties where exposure was high or where credit quality of the counterparty had deteriorated. 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 September 30, 2009, total credit exposure to substantially all counterparties was $1.8 billion and NRG held collateral (cash and letters of credit) against those positions of $280 million resulting in a net exposure of $1.5 billion. Total credit exposure is discounted at the 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, includes amounts net of receivables or payables and excludes non-affiliate third party exposure under the CSRA.


	Net Exposure ^(a)(b)
	as of September 30, 2009
Category	(% of Total)

Financial institutions		81	%
Utilities, energy, merchants, marketers and other		13
Coal suppliers		3
ISOs		3

Total		100	%


	Net Exposure ^(a)(b)
	as of September 30, 2009
Category	(% of Total)

Investment grade		93	%
Non-Investment grade		2
Non-rated		5

Total		100	%


(a)		Credit exposure excludes California tolling, uranium, coal transportation, New England Reliability Must-Run, cooperative load contracts, and Texas Westmoreland coal contracts. The aforementioned exposures were excluded for various reasons including regulatory support or liens held against the contracts which serve to reduce the risk of loss, or credit risks for certain contracts are not readily measurable due to a lack of market reference prices.

(b)		The exposure amounts presented in the above table do not include non-affiliate third party exposure under the CSRA which was amended on October 5, 2009. The gross credit exposure to third parties under the CSRA was $385 million, and the cash collateral held by Merrill Lynch against this exposure was $304 million.

NRG has credit risk exposure to certain counterparties representing more than 10% of total net exposure and the aggregate of such counterparties was $704 million. Approximately 72% 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.

NRG is exposed to retail credit risk through our competitive electricity supply business, which serves C&I customers and the Mass market in Texas. Retail credit risk results when a customer fails to pay for services rendered. The losses could be incurred from nonpayment of customer accounts receivable and any in-the-money forward value. NRG manages retail credit risk through the use of established credit policies that include monitoring of the portfolio, and the use of credit mitigation measures such as deposits or prepayment arrangement. Retail credit risk is dependent on the overall economy, but is minimized due to the fact that NRG’s portfolio of retail customers is largely diversified, with no significant single name concentration.

Accumulated Other Comprehensive Income

The following table summarizes the effects of ASC 815 on NRG’s accumulated OCI balance attributable to hedged derivatives, net of tax:


(In millions)	Energy			Interest
Three months ended September 30, 2009	Commodities			Rate			Total

Accumulated OCI balance at June 30, 2009	$	445		$	(66	)	$	379
Realized from OCI during the period:
— Due to realization of previously deferred amounts		(75	)		—			(75	)
Mark-to-market of cash flow hedge accounting contracts		4			(2	)		2

Accumulated OCI balance at September 30, 2009	$	374		$	(68	)	$	306

Gains/(losses) expected to be realized from OCI during the next 12 months, net of $172 tax	$	288		$	(3	)	$	285


(In millions)	Energy			Interest
Three months ended September 30, 2008	Commodities			Rate			Total

Accumulated OCI balance at June 30, 2008	$	(1,235	)	$	(30	)	$	(1,265	)
Realized from OCI during the period:
— Due to realization of previously deferred amounts		26			—			26
Mark-to-market of cash flow hedge accounting contracts		1,088			(2	)		1,086

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


(In millions)	Energy			Interest
Nine months ended September 30, 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		(263	)		—			(263	)
— Due to discontinuance of cash flow hedge accounting		(135	)		—			(135	)
Mark-to-market of cash flow hedge accounting contracts		366			23			389

Accumulated OCI balance at September 30, 2009	$	374		$	(68	)	$	306


(In millions)	Energy			Interest
Nine months ended September 30, 2008	Commodities			Rate			Total

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

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

As of September 30, 2009, the net balance in OCI relating to ASC 815 was an unrecognized gain of approximately $306 million, which is net of $189 million in income taxes. As of September 30, 2008, the net balance in OCI relating to ASC 815 was an unrecognized loss of approximately $153 million, which was net of $102 million in income taxes.

Accounting guidelines require a high degree of correlation between the derivative and the hedged item throughout the period in order to qualify as a cash flow hedge. 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 marked these derivatives to market. On April 1, 2009, the required correlation threshold for cash flow hedge accounting was achieved for these transactions, and accordingly, these hedges were re-designated as cash flow hedges.

As discussed in Note 4, Business Acquisition, to this Form 10-Q, in conjunction with the CSRA, PML and REPS modified or novated certain transactions with counterparties. The novated transactions are financial sales of natural gas to the counterparties covering the period from 2009 through 2012 to hedge NRG’s Texas baseload generation. A portion of these transactions were accounted for as cash flow hedges. The effective portion of the fair value of these transactions recorded in OCI was approximately $245 million. On the date of novation, NRG elected to de-designate these cash flow hedges and to recognize future changes in value in earnings prospectively. As the underlying baseload power generation is still probable, the gains through the date of novation related to the cash flow hedges remain frozen in OCI and will be amortized into income when the underlying power is generated. Approximately $248 million of the fair values of these transactions at the novation date were accounted for as mark-to-market transactions through the income statement both before and after the novations.

As discussed in Note 20, Subsequent Event, to this Form 10-Q, NRG amended the CSRA effective October 5, 2009, and net settled or offset certain REPS transactions with counterparties.

Statement of Operations

In accordance with ASC 815, 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 September 30,						Nine months ended September 30,
(In millions)	2009			2008			2009			2008

Unrealized mark-to-market results
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	1		$	(7	)	$	(33	)	$	(32	)
Reversal of loss positions acquired as part of the Reliant Energy acquisition as of May 1, 2009		238			—			448			—
Reversal of previously recognized unrealized gains on settled positions related to trading activity		(21	)		(9	)		(125	)		(20	)
Net unrealized (losses)/gains on open positions related to economic hedges		(239	)		439			70			180
Gains/(losses) on ineffectiveness associated with open positions treated as cash flow hedges		16			352			17			(27	)
Net unrealized (losses)/gains on open positions related to trading activity		(9	)		60			(1	)		91

Total unrealized (losses)/gains	$	(14	)	$	835		$	376		$	192


	Three months ended September 30,						Nine months ended September 30,
(In millions)	2009			2008			2009			2008

Revenue from operations — energy commodities	$	(217	)	$	835		$	(100	)	$	192
Cost of operations		203			—			476			—

Total impact to statement of operations	$	(14	)	$	835		$	376		$	192

For the nine months ended September 30, 2009, the unrealized gain associated with changes in the fair value of derivative instruments not accounted for as hedge derivatives of $376 million was comprised of gains of $70 million from fair value increases in forward sales and purchases of natural gas, electricity and fuel, $17 million gain from ineffectiveness, $158 million loss from the reversal of mark-to-market gains, $448 million roll-off of Reliant Energy loss positions acquired as of May 1, 2009, and $1 million of losses associated with the Company’s trading activity. The $70 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 a $147 million increase in value of forward purchases and sales of natural gas, electricity and fuel due to decrease in forward power and gas prices. The $17 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. This amount is included in the Company’s cost of operations.

The Reliant Energy’s loss positions were acquired as of May 1, 2009 and valued using forward prices on that date. The $448 million roll-off amounts were offset by realized losses at the settled prices and are reflected in the cost of operations during the same period.

For the nine months ended September 30, 2008, the unrealized gain associated with changes in the fair value of derivative instruments not accounted for as hedge derivatives of $192 million was comprised of $180 million of fair value increases in forward sales of electricity and fuel, a $27 million loss due to the ineffectiveness associated with financial forward contracted electric and gas sales, $52 million from the reversal of mark-to-market gains which ultimately settled as financial revenues of which $32 million was related to economic hedges and $20 million was related to trading activity. These decreases were partially offset by $91 million of gains associated with open positions related to trading activity.

Discontinued Hedge Accounting — During the first half of 2009, a relatively sharp decline in commodity prices resulted in falling power prices and 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 nine months ended September 30, 2009.

Discontinued Normal Purchase and Sale for Coal Purchases — Due to lower coal-fired generation during the first quarter 2009, the Company’s coal consumption was lower than forecasted. The Company net settled some of its coal purchases under NPNS designation and thus was no longer 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 first quarter and prospectively. The impact of discontinuance of coal NPNS designated transactions resulted in a derivative loss of $29 million that is reflected in the cost of operations for the nine months ended September 30, 2009.

Note 8 — Long-Term Debt

2019 Senior Notes

On June 5, 2009, NRG issued $700 million aggregate principal amount of 8.5% Senior Notes due 2019, or 2019 Senior Notes, at a discount resulting in a yield of 8.75%. The 2019 Senior Notes were issued under an Indenture, dated February 2, 2006, between NRG and Law Debenture Trust Company of New York, as trustee, as amended through Supplemental Indentures, which is discussed in Note 11, Debt and Capital Leases, in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008. The Indentures and the form of the notes provide, among other things, that the 2019 Senior Notes will be senior unsecured obligations of NRG.

A portion of the net proceeds of $678 million were used to facilitate the early termination of NRG’s obligations pursuant to the CSRA Amendment, which became effective on October 5, 2009, as discussed in Note 20, Subsequent Event, to this Form 10-Q. Interest is payable semi-annually on the 2019 Senior Notes beginning on December 15, 2009, until their maturity date of June 15, 2019. As of September 30, 2009, $700 million in principal was outstanding under the 2019 Senior Notes.

Prior to June 15, 2012, NRG may redeem up to 35% of the aggregate principal amount of the 2019 Senior Notes with the net proceeds of certain equity offerings, at a redemption price of 108.5% of the principal amount. Prior to June 15, 2014, NRG may redeem all or a portion of the 2019 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of (i) 1% of the principal amount of the note; or (ii) the excess of the principal amount of the note over the following: the present value of 104.25% of the note, plus interest payments due on the note from the date of redemption through June 15, 2014, discounted at a Treasury rate plus 0.50%. In addition, on or after June 15, 2014, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:


	Redemption
Redemption Period	Percentage

June 15, 2014 to June 14, 2015		104.25	%
June 15, 2015 to June 14, 2016		102.83	%
June 15, 2016 to June 14, 2017		101.42	%
June 15, 2017 and thereafter		100.00	%

Interest Rate Swaps

In May 2009, NRG entered into a series of forward-starting interest rate swaps. These interest rate swaps become effective on April 1, 2011, and are intended to hedge the risks associated with floating interest rates. For each of the interest rate swaps, the Company will pay its counterparty the equivalent of a fixed interest payment on a predetermined notional value, and NRG receives the monthly equivalent of a floating interest payment based on a 1-month LIBOR calculated on the same notional value. All interest rate swap payments by NRG and its counterparties are made monthly and the LIBOR is determined in advance of each interest period. The total notional amount of these swaps is $900 million. The swaps mature on February 1, 2013.

Reliant Energy Acquisition

See discussion in Note 4, Business Acquisition, to this Form 10-Q, regarding the CSRA entered into as a result of the acquisition of Reliant Energy on May 1, 2009. Further, see discussion in Note 4, Business Acquisition, to this Form 10-Q, regarding the $50 million working capital facility entered into on May 1, 2009. Under the working capital facility, the Company borrowed $25 million on May 1, 2009. On October 5, 2009, $25 million was repaid on the working capital facility, which was terminated in conjunction with the amendment of the CSRA as discussed in Note 20, Subsequent Event, to this Form 10-Q.

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 Units 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 September 30, 2009, no amounts have been borrowed 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 CS relating to the shares of NRG common stock currently held by CSF I and II in connection with the CSF Debt originally entered into during the third quarter 2006, by and between CSF I and II and affiliates of CS. The Company entered into Share Lending Agreements due to a 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 September 30, 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 Agreements 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, to this Form 10-Q, the Company adopted FSP APB 14-1 on January 1, 2009, which has been incorporated in ASC 470 and ASC 825. The following table summarizes certain information related to the CSF Debt in accordance with ASC 470.


	September 30,			December 31,
	2009			2008

Equity Component
Additional Paid-in Capital	$	14		$	14

Liability Component
Principal amount	$	333		$	333
Unamortized discount		(3	)		(8	)

Net carrying amount	$	330		$	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 of October 2009. Interest expense for the CSF Debt, including the debt discount amortization for the three and nine months ended September 30, 2009, was $10 million and $28 million, respectively. Interest expense for the CSF Debt, including the debt discount amortization for the three and nine months ended September 30, 2008, was $9 million and $28 million, respectively. The effective interest rate as of September 30, 2009, was 11.4% for the CSF I Debt and 12.1% for the CSF II Debt.

Subsequent Event — On October 9, 2009, NRG commenced the process of unwinding the CSF II Debt, making a $181.4 million capital contribution to a CSF II cash account, effectively restricting the cash for the benefit of CS. On October 13, 2009, CS began the process of unwinding their hedges in connection with the CSF II structure, which they are required to complete by November 24, 2009. Once complete, CS is scheduled to return 5,400,000 shares of NRG common stock borrowed under the Share Lending Agreements, and release 9,528,930 common shares held as collateral for the CSF II Debt, and the Company will remit payment to CS of the $181.4 million outstanding principal and interest.

The CSF II Debt contains an embedded derivative feature, or CFS II CAGR, which requires NRG to pay 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 of $40.80 per share. On November 24, 2009, the CSF II CAGR will also be evaluated to determine whether any payment is due to CS, at which point the CSF II CAGR will expire.

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 used for 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 proceeds received through September 30, 2009, were $38 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 covering amounts drawn on the 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 requires mandatory prepayment of the portion of the loan utilized to pay costs of the Devon project, of approximately $56 million, on the earlier of Devon’s commercial operations date or January 27, 2011. The proceeds of the EBL received through September 30, 2009, were $88 million and the remaining amounts will be drawn as necessary to fund construction costs.

In April 2009, GenConn secured financing for 50% of the Devon and Middletown project construction costs through a 7-year term loan facility, and also entered into a 5-year revolving working capital loan and letter of credit facility, which collectively with the term loan is referred to as the GenConn Facility. The aggregate credit amount secured under the GenConn Facility, which is non-recourse to NRG, is $291 million, including $48 million for the revolving facility. In August 2009, GenConn began to draw under the GenConn Facility to cover costs related to the Devon project and as of September 30, 2009, has drawn $19 million.

Note 9 — Changes in Capital Structure

The following table reflects the changes in NRG’s common stock issued and outstanding during the nine months ended September 30, 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		—		268,220		—			268,220
Shares issued under NRG Employee Stock Purchase Plan, or ESPP		—		—		81,532			81,532
Shares borrowed by affiliates of CS		—		—		12,000,000			12,000,000
2009 Share Repurchases		—		—		(8,919,100	)		(8,919,100	)
4.00% Preferred Stock conversion		—		20,650		—			20,650
5.75% Preferred Stock conversion		—		18,601,201		—			18,601,201

Balance as of September 30, 2009		500,000,000		282,489,271		(26,080,051	)		256,409,220

Employee Stock Purchase Plan

As of September 30, 2009, there were 418,468 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 September 30, 2009		—				18,601,201

4% Preferred Stock

As of September 30, 2009, 413 shares of the 4% Preferred Stock were converted into 20,650 shares of common stock in 2009.

2009 Capital Allocation Program

In July 2009, as part of the Company’s 2009 Capital Allocation Program, NRG’s Board of Directors approved an increase to the Company’s previously authorized common share repurchases under its capital allocation plan from the existing $330 million to $500 million. The Company’s repurchases during the period ended September 30, 2009, were $250 million. NRG intends to complete its $500 million of share repurchases by the end of 2009, subject to market prices, financial restrictions under the Company’s debt facilities, and as permitted by securities laws.

Note 10 — Equity Compensation

Non-Qualified Stock Options, or NQSO’s

The following table summarizes the Company’s NQSO activity as of September 30, 2009, and changes during the nine 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		1,402,000			23.62
Exercised		(25,000	)		21.41
Forfeited		(212,935	)		27.55

Outstanding at September 30, 2009		5,172,253			25.19	$	29.71
Exercisable at September 30, 2009		2,815,800		$	21.80	$	22.98

The weighted average grant date fair value of NQSO’s granted for the nine months ended September 30, 2009, was $8.63.

Restricted Stock Units, or RSU’s

The following table summarizes the Company’s non-vested RSU awards as of September 30, 2009, and changes during the nine 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		927,000			26.12
Vested		(334,752	)		23.24
Forfeited		(45,850	)		33.59

Non-vested as of September 30, 2009		1,608,394		$	31.03

Performance Units, or PU’s

The following table summarizes the Company’s non-vested PU awards as of September 30, 2009, and changes during the nine months then ended:


				Weighted Average
				Grant- Date
	Units			Fair Value Per Unit

Non-vested as of December 31, 2008		659,564		$	22.81
Granted		338,100			22.91
Forfeited		(272,864	)		19.44

Non-vested as of September 30, 2009		724,800		$	24.29

In the nine months ended September 30, 2009, there were no performance unit payouts in accordance with the terms of the performance units.

Deferral Stock Units, or DSU’s

The following table summarizes the Company’s outstanding DSU awards as of September 30, 2009, and changes during the nine months then ended:


				Weighted Average
				Grant- Date
	Units			Fair Value Per Unit

Outstanding as of December 31, 2008		260,768		$	18.50
Granted		65,437			22.77
Conversions		(22,156	)		23.69

Outstanding as of September 30, 2009		304,049		$	19.34

Note 11 — 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 8, Long-Term Debt, to this Form 10-Q, 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						Nine months ended
	September 30,						September 30,
(In millions, except per share data)	2009			2008			2009			2008

*Basic earnings per share attributable to NRG common stockholders*
Numerator:
Income from continuing operations, net of income taxes	$	278		$	778		$	909		$	782
Dividends for preferred shares		(6	)		(13	)		(27	)		(41	)

Net income available to common stockholders from continuing operations		272			765			882			741
Income from discontinued operations, net of income taxes		—			—			—			172

Net income attributable to NRG Energy, Inc. available to common stockholders	$	272		$	765		$	882		$	913

Denominator:
Weighted average number of common shares outstanding		249.3			234.8			246.6			235.7
*Basic earnings per share:*
Income from continuing operations	$	1.09		$	3.26		$	3.58		$	3.14
Income from discontinued operations, net of income taxes		—			—			—			0.73

Net income attributable to NRG Energy, Inc.	$	1.09		$	3.26		$	3.58		$	3.87

*Diluted earnings per share attributable to NRG common stockholders*
Numerator:
Net income available to common stockholders from continuing operations	$	272		$	765		$	882		$	741
Add preferred stock dividends for dilutive preferred stock		4			11			19			34

Adjusted income from continuing operations		276			776			901			775
Income from discontinued operations, net of income taxes		—			—			—			172

Net income attributable to NRG Energy, Inc. available to common stockholders	$	276		$	776		$	901		$	947

Denominator:
Weighted average number of common shares outstanding		249.3			234.8			246.6			235.7
Incremental shares attributable to the issuance of equity compensation (treasury stock method)		1.5			2.2			1.1			3.0
Incremental shares attributable to embedded derivatives of 3.625% redeemable perpetual preferred stock (if-converted method)		—			2.0			—			1.8
Incremental shares attributable to assumed conversion features of outstanding preferred stock (if-converted method)		21.0			37.5			26.4			37.5

Total dilutive shares		271.8			276.5			274.1			278.0
*Diluted earnings per share:*
Income from continuing operations	$	1.02		$	2.81		$	3.29		$	2.79
Income from discontinued operations, net of income taxes		—			—			—			0.62

Net income attributable to NRG Energy, Inc.	$	1.02		$	2.81		$	3.29		$	3.41

Effects on Earnings per Share

The following table summarizes NRG’s outstanding equity instruments that were anti-dilutive and not included in the computation of the Company’s diluted earnings per share for the three and nine months ended September 30:


	Three months ended September 30,				Nine months ended September 30,
(In millions of shares)	2009		2008		2009		2008

Equity compensation (NQSO’s and PU’s)		4.8		1.8		6.4		1.4
Embedded derivative of 3.625% redeemable perpetual preferred stock		16.0		14.0		16.0		14.2
Embedded derivative of CSF II Debt		7.6		7.6		7.6		7.6

Total		28.4		23.4		30.0		23.2

Note 12 — Segment Reporting

NRG’s segment structure has changed to reflect the Company’s acquisition of Reliant Energy along with the previously reported 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.

In the second quarter 2009, management changed its method for allocating corporate general and administrative expenses to the segments. Corporate general and administrative expenses had been allocated based on budgeted segment revenues. Beginning in the second quarter 2009, corporate general and administrative expenses have been allocated based on forecasted earnings/(losses) before interest expense, income taxes, depreciation and amortization expense.


(In millions)				Wholesale Power Generation
Three months ended	Reliant							South
September 30, 2009	Energy			Texas ^(a)		Northeast		Central			West		International		Thermal			Corporate			Elimination			Total

Operating revenues	$	1,790		$	760	$	270	$	143		$	40	$	38	$	33		$	(3	)	$	(155	)	$	2,916
Depreciation and amortization		42			119		29		16			2		—		2			2			—			212
Equity in earnings of unconsolidated affiliates		—			—		—		—			4		2		—			—			—			6
Income/(loss) from continuing operations before income taxes		393			196		50		(34	)		16		7		2			(186	)		—			444
Net income/(loss) attributable to NRG Energy, Inc.	$	393		$	196	$	50	$	(34	)	$	16	$	6	$	2		$	(351	)	$	—		$	278

Total assets	$	4,048		$	13,634	$	1,823	$	914		$	278	$	791	$	198		$	22,602		$	(18,334	)	$	25,954


(a) Includes inter-segment sales of $162 million to Reliant Energy. If the Company continued using the 2008 allocation method for corporate general and administrative expenses, the effect to net income/(loss) of each segment for the three months ended September 30, 2009, would have been as follows:

Net income/(loss) attributable to NRG Energy, Inc. as reported	$	393		$	196	$	50	$	(34	)	$	16	$	6	$	2		$	(351	)	$	—		$	278
Increase/(decrease) in net income/(loss) attributable to NRG Energy, Inc.		(19	)		14		6		(1	)		—		1		(1	)		—			—			—

Adjusted net income/(loss) attributable to NRG Energy, Inc.	$	374		$	210	$	56	$	(35	)	$	16	$	7	$	1		$	(351	)	$	—		$	278


				Wholesale Power Generation
(In millions)								South
Three months ended September 30, 2008				Texas		Northeast		Central			West		International		Thermal			Corporate			Elimination			Total

Operating revenues				$	1,637	$	622	$	234		$	40	$	41	$	36		$	3		$	(1	)	$	2,612
Depreciation and amortization					108		26		16			2		—		3			1			—			156
Equity in earnings of unconsolidated affiliates					40		—		—			1		17		—			—			—			58
Income/(loss) from continuing operations before income taxes					1,026		296		25			13		25		4			(108	)		(1	)		1,280
Net income/(loss) attributable to NRG Energy, Inc.				$	576	$	296	$	25		$	13	$	19	$	4		$	(154	)	$	(1	)	$	778


(In millions)				Wholesale Power Generation
Nine months ended	Reliant								South
September 30, 2009	Energy ^(a)			Texas ^(b)			Northeast		Central			West			International		Thermal		Corporate			Elimination			Total

Operating revenues	$	2,965		$	2,304		$	971	$	444		$	110		$	106	$	103	$	33		$	(225	)	$	6,811
Depreciation and amortization		85			353			88		50			6			—		7		5			—			594
Equity in earnings/(losses) of unconsolidated affiliates		—			(3	)		—		—			8			28		—		—			—			33
Income/(loss) from continuing operations before income taxes		807			681			303		(42	)		32			149		6		(414	)		—			1,522
Net income/(loss)		807			510			303		(42	)		32			143		6		(851	)		—			908
Net loss attributable to non-controlling interest		—			(1	)		—		—			—			—		—		—			—			(1	)
Net income/(loss) attributable to NRG Energy, Inc.	$	807		$	511		$	303	$	(42	)	$	32		$	143	$	6	$	(851	)	$	—		$	909

(a) Reliant Energy balances are for the five months ended September 30, 2009. (b) Includes inter-segment sales of $228 million to Reliant Energy. If the Company continued using the 2008 allocation method for corporate general and administrative expenses, the effect to net income/(loss) of each segment for the nine months ended September 30, 2009, would have been as follows:

Net income/(loss) attributable to NRG Energy, Inc. as reported	$	807		$	511		$	303	$	(42	)	$	32		$	143	$	6	$	(851	)	$	—		$	909
Increase/(decrease) in net income/(loss) attributable to NRG Energy, Inc.		(30	)		22			9		(2	)		1			—		—		—			—			—

Adjusted net income/(loss) attributable to NRG Energy, Inc.	$	777		$	533		$	312	$	(44	)	$	33		$	143	$	6	$	(851	)	$	—		$	909


(In millions)				Wholesale Power Generation
									South
Nine months ended September 30, 2008				Texas			Northeast		Central			West			International		Thermal		Corporate			Elimination			Total

Operating revenues				$	3,037		$	1,247	$	585		$	127		$	122	$	114	$	1		$	(3	)	$	5,230
Depreciation and amortization					334			77		50			6			—		8		3			—			478
Equity in (losses)/earnings of unconsolidated affiliates					(10	)		—		—			(2	)		47		—		—			—			35
Income/(loss) from continuing operations before income taxes					1,107			310		58			38			72		11		(300	)		(11	)		1,285
Income from discontinued operations, net of income taxes					—			—		—			—			172		—		—			—			172
Net income/(loss) attributable to NRG Energy, Inc.				$	626		$	310	$	58		$	38		$	229	$	11	$	(307	)	$	(11	)	$	954

Note 13 — Income Taxes

Effective Tax Rate

Income taxes included in continuing operations were as follows:


	Three months ended September 30,
(In millions except otherwise noted)	2009			2008

Income tax expense	$	166		$	502
Effective tax rate		37.4	%		39.2	%

For the three months ended September 30, 2009, NRG’s overall effective tax rate on continuing operations was different than the statutory rate of 35% primarily due to the U.S. taxation of foreign earnings offset by a reduction in the valuation allowance. For the three months ended September 30, 2008, NRG’s effective tax rate was increased primarily due to the impact of state and local income taxes.

Income taxes included in continuing operations were as follows:


	Nine months ended September 30,
(In millions except otherwise noted)	2009			2008

Income tax expense	$	614		$	503
Effective tax rate		40.3	%		39.1	%

For the nine months ended September 30, 2009, NRG’s overall effective tax rate on continuing operations was different than the statutory rate of 35% primarily due to an increase in the valuation allowance as a result of capital losses generated during the nine months for which there are no projected capital gains or available tax planning strategies. For the nine months ended September 30, 2008, NRG’s overall effective tax rate was increased primarily due to the impact of state and local income taxes.

Deferred tax assets, liabilities and valuation allowance

On a provisional basis, NRG established deferred tax assets of $1,203 million and deferred tax liabilities of $1,189 million as a result of NRG’s acquisition of Reliant Energy.

In addition, the Company anticipates reversal of the deferred tax assets and corresponding valuation allowance pertaining to capital losses which will expire on December 31, 2009.

Valuation Allowance

As of September 30, 2009, the Company’s valuation allowance was increased by approximately $63 million primarily due to losses generated in the period from derivative trading activity which require capital treatment for tax purposes. The Company increased its foreign valuation allowance by approximately $13 million.

Uncertain tax benefits

As of September 30, 2009, NRG has recorded a $688 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 and penalties related to these unrecognized tax benefits of approximately $11 million for the nine months ended September 30, 2009, and has accrued approximately $19 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 U.S. federal jurisdiction and various state and foreign jurisdictions including major operations located in Germany and Australia. The Company is no longer subject to U.S. federal income tax examinations for years prior to 2002. With few exceptions, state and local income tax examinations are no longer open for years before 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.

Tax Receivable and Payable

As of September 30, 2009, the Company has recorded a tax receivable of approximately $51 million that represents a domestic federal tax receivable of $9 million and state tax receivable of $42 million, net of $6 million reserve. In addition, the Company has recorded a current payable of approximately $56 million which includes domestic tax payable of approximately $45 million as well as foreign taxes payable of approximately $11 million.

Note 14 — 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 employees. The total amount of employer contributions paid for the nine months ended September 30, 2009, was $22 million. NRG expects to make $5 million in further contributions for the remainder of 2009. The total 2009 planned contribution of $27 million was a decrease of $33 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 Plans
	Three months ended September 30,						Nine months ended September 30,
(In millions)	2009			2008			2009			2008

Service cost benefits earned	$	4		$	4		$	11		$	11
Interest cost on benefit obligation		5			4			15			13
Prior service cost		—			—			1			—
Net gain		—			—			—			(1	)
Expected return on plan assets		(4	)		(4	)		(12	)		(11	)

Net periodic benefit cost	$	5		$	4		$	15		$	12

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


	Other Postretirement Benefits Plans
	Three months ended September 30,				Nine months ended September 30,
(In millions)	2009		2008		2009		2008

Service cost benefits earned	$	—	$	1	$	2	$	2
Interest cost on benefit obligation		3		1		5		4

Net periodic benefit cost	$	3	$	2	$	7	$	6

STP Defined Benefit Plans

NRG has a 44% undivided ownership interest in STP. South Texas Project Nuclear Operating Company, or STPNOC, which operates and maintains STP, provides its employees a defined benefit pension plan as well as postretirement health and welfare benefits. Although NRG does not sponsor the STP plan, it reimburses STPNOC for 44% of the contributions made towards its retirement plan obligations. The total amount of employer contributions reimbursed to STPNOC for the nine months ended September 30, 2009, was $3 million. 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 September 30, 2009, and 2008, respectively. The Company recognized net periodic costs related to its 44% interest in STP defined benefits plans of $8 million and $6 million for the nine months ended September 30, 2009, and 2008, respectively.

Note 15 — Commitments and Contingencies

Operating Lease Commitments

As a result of the acquisition of Reliant Energy, the Company’s operating lease commitments have increased primarily due to additional lease agreements for office space through 2021. As of September 30, 2009, eight additional office space locations were under lease for future commitments of approximately $85 million.

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 $409 million during the nine months ended September 30, 2009, as the 2009 monthly commitments were settled. In addition, NRG’s natural gas purchase commitments decreased by approximately $199 million during the nine months ended September 30, 2009, as the 2009 monthly commitments were settled and average natural gas prices decreased.

Purchased Power Commitments

As a result of the acquisition of Reliant Energy, NRG is party to purchased power contracts of various quantities and durations that are not classified as derivative assets and liabilities. These contracts are not included in the consolidated balance sheet as of September 30, 2009. Minimum purchase commitment obligations under these agreements are as follows as of September 30, 2009:


(In millions)	Fixed Pricing ^(a)		Variable Pricing ^(b)

Remainder of 2009	$	23	$	36
2010		54		7
2011		30		3
2012		21		1
2013		10		—

Total	$	138	$	47


(a)		As of September 30. 2009, the maximum remaining term under any individual purchased power contract is four years.
(b)		For contracts with variable pricing components, estimated prices are based on forward commodity curves as of September 30, 2009.

Other

As a result of the acquisition of Reliant Energy, the Company acquired the naming rights, including advertising and other benefits, for a football stadium and other convention and entertainment facilities included in the stadium complex in Houston, Texas. Pursuant to this agreement, the Company is required to pay $10 million per year through 2031.

See discussion in Note 4, Business Acquisition, to this Form 10-Q, regarding the CSRA as a result of the acquisition of Reliant Energy on May 1, 2009.

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 September 30, 2009, and October 22, 2009, all hedges under the first and second liens were in-the-money on a counterparty aggregate basis.

RepoweringNRG Initiatives

NRG has capitalized $32 million through September 30, 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 working with the counterparty to consider 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 ASC 450 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. On April 17, 2009, NRG and NRG’s Board of Directors filed a partial motion to dismiss the amended complaint. On July 28, 2009, Exelon, NRG, and NRG’s Board of Directors collectively filed a Stipulation of Dismissal of Exelon’s lawsuit, thereby ending the case.

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. 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. On August 4, 2009, the plaintiffs filed a notice and proposed order of dismissal and on August 5, 2009, the court dismissed the lawsuit, thereby ending the case.

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. 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, and again on May 7, 2009, oral argument was held and on June 18, 2009, the court found in favor of NRG’s Board of Directors and stayed the consolidated lawsuits pending resolution of the purported class-action lawsuit filed in Delaware Chancery court by the Louisiana Sheriffs’ Pension & Relief Fund and City of St. Claire Shores Police & Fire Retirement System. On August 10, 2009, the plaintiffs filed a Notice of Voluntary Dismissal, thereby ending the case.

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 U.S. 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 U.S. 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: (i) that the Mobile-Sierra public interest standard of review applied to contracts made under a seller’s market-based rate authority; (ii) that the public interest “bar” required to set aside a contract remains a very high one to overcome; and (iii) 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 U.S. Supreme Court affirmed the Ninth Circuit’s decision agreeing that the case should be remanded to the FERC to clarify the 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 U.S. 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 U.S. 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 U.S. Supreme Court’s June 26, 2008 decision. On December 15, 2008, WCP and the other seller-defendants filed with the 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 U.S. 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. The settlement, filed with the 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 DC Circuit 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. NRG sought certiorari before the U.S. Supreme Court, which was granted on April 27, 2009. Oral argument is scheduled for November 3, 2009.

Louisiana Generating, LLC

On February 11, 2009, the U.S. Department of Justice acting at the request of the U.S. Environmental Protection Agency, or U.S. EPA, 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: (i) preclude the operation of Units 1 and 2 except in accordance with the CAA; (ii) order the installation of BACT on Units 1 and 2 for each pollutant subject to regulation under the CAA; (iii) obtain all necessary permits for Units 1 and 2; (iv) order the surrender of emission allowances or credits; (v) conduct audits to determine if any additional modifications have been made which would require compliance with the CAA’s Prevention of Significant Deterioration program; (vi) award to the Department of Justice its costs in prosecuting this litigation; and (vii) 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. It filed an objection in the Cajun Electric Cooperative Power, Inc.’s bankruptcy proceeding in the U.S. Bankruptcy Court for the Middle District of Louisiana to seek to prevent the bankruptcy from closing. It also 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. On June 8, 2009, the parties filed a joint status report setting forth their views of the case and proposing a trial schedule. On June 18, 2009, Louisiana Generating, LLC filed a motion to bifurcate the Department of Justice lawsuit into separate liability and remedy phases, and on June 30, 2009, the Department of Justice filed its opposition. On August 24, 2009, Louisiana Generating, LLC filed a motion to dismiss this lawsuit, and on September 25, 2009, the Department of Justice filed its opposition to the motion to dismiss. A new federal bankruptcy judge was appointed on October 9, 2009.

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. 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. On July 23, 2009, the court dismissed the matter, thereby ending the case.

Excess Mitigation Credits

From January 2002 to April 2005, CenterPoint Energy applied excess mitigation credits, or EMCs, to its monthly charges to retail electric providers as ordered by the Public Utility Commission of Texas, or PUCT. The PUCT imposed these credits to facilitate the transition to competition in Texas, which had the effect of lowering the retail electric providers’ monthly charges payable to CenterPoint Energy. As indicated in its Petition for Review filed with the Supreme Court of Texas on June 2, 2008, CenterPoint Energy has claimed that the portion of those EMCs credited to Reliant Energy Retail Services, LLC, or RERS, a retail electric provider and NRG subsidiary acquired from RRI, totaled $385 million for RERS’s “Price to Beat” Customers. It is unclear what the actual number may be. “Price to Beat” was the rate RERS was required by state law to charge residential and small commercial customers that were transitioned to RERS from the incumbent integrated utility company commencing in 2002. In its original stranded cost case brought before the PUCT on March 31, 2004, CenterPoint Energy sought recovery of all EMCs that were credited to all retail electric providers, including RERS, and the PUCT ordered that relief in its Order on Rehearing in Docket No. 29526, on December 17, 2004. After an appeal to state district court, the court entered a final judgment on August 26, 2005, affirming the PUCT’s order with regard to EMCs credited to RERS. Various parties filed appeals of that judgment with the Court of Appeals for the Third District of Texas with the first such appeal filed on the same date as the state district court judgment and the last such appeal filed on October 10, 2005. On April 17, 2008, the Court of Appeals for the Third District reversed the lower court’s decision ruling that CenterPoint Energy’s stranded cost recovery should exclude only EMCs credited to RERS for its “Price to Beat” customers. On June 2, 2008, CenterPoint Energy filed a Petition for Review with the Supreme Court of Texas and on June 19, 2009, the Court agreed to consider the CenterPoint Energy appeal as well as two related petitions for review filed by other entities. Oral argument occurred on October 6, 2009.

In November 2008, CenterPoint Energy and RRI, on behalf of itself and affiliates including RERS, agreed to suspend unexpired deadlines, if any, related to limitations periods that might exist for possible claims against REI and its affiliates if CenterPoint Energy is ultimately not allowed to include in its stranded cost calculation those EMCs previously credited to RERS. Regardless of the outcome of the Texas Supreme Court proceeding, NRG believes that any possible future CenterPoint Energy claim against RERS for EMCs credited to RERS would lack legal merit. No such claim has been filed.

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. 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.

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 and on July 13, 2009, that distribution was complete.

Note 16 — 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 power markets are subject to ongoing legislative and regulatory changes that may impact NRG’s wholesale and retail businesses.

In addition to the regulatory proceedings noted below, NRG and its subsidiaries are a party to other regulatory proceedings arising in the ordinary course of business or have other regulatory exposure. 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.

PJM — By Order dated March 17, 2009, the U.S. Court of Appeals for the DC Circuit denied the remaining appeals of the FERC orders establishing the Reliability Pricing Model, or 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 June 18, 2009, FERC denied rehearing of its order dated September 19, 2008, dismissing a complaint filed by the Maryland Public Service Commission, or MDPSC, together with other load interests, against PJM challenging the results of the RPM transition Base Residual Auctions for installed capacity, held between April 2007 and January 2008. The complaint had 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 August 14, 2009, the MDPSC and the New Jersey Board of Public Utilities filed an appeal of FERC’s orders to the U.S. Court of Appeals for the Fourth Circuit, and a successful appeal could disrupt the auction-determined results and create a refund obligation for market participants.

Retail (Replacement Reserve) — On November 14, 2006, Constellation Energy Commodities Group, or Constellation, filed a complaint with the PUCT alleging that ERCOT misapplied the Replacement Reserve Settlement, or RPRS, Formula contained in the ERCOT protocols from April 10, 2006, through September 27, 2006. Specifically, Constellation disputed approximately $4 million in under-scheduling charges for capacity insufficiency asserting that ERCOT applied the wrong protocol. Reliant Energy Power Supply, or REPS, other market participants, ERCOT, and PUCT staff opposed Constellation’s complaint. On January 25, 2008, the PUCT entered an order finding that ERCOT correctly settled the capacity insufficiency charges for the disputed dates in accordance with ERCOT protocols and denied Constellation’s complaint. On April 9, 2008, Constellation appealed the PUCT order to the Civil District Court of Travis County, Texas and on June 19, 2009, the court issued a judgment reversing the PUCT order, finding that the ERCOT protocols were in irreconcilable conflict with each other. On July 20, 2009, REPS filed an appeal to the Third Court of Appeals in Travis County, Texas, thereby staying the effect of the trial court’s decision. If all appeals are unsuccessful, on remand to the PUCT, it would determine the appropriate methodology for giving effect to the trial court’s decision. It is not known at this time whether only Constellation’s under-scheduling charges, the under-scheduling charges of all other QSEs that disputed REPS charges for the same time frame, the entire market, or some other approach would be used for any resettlement.

Under the PUCT ordered formula, Qualified Scheduling Entities, or QSEs, who under-scheduled capacity within any of ERCOT’s four congestion zones were assessed under-scheduling charges which defrayed the costs incurred by ERCOT for RPRS that would otherwise be spread among all load-serving QSEs. Under the Court’s decision, all RPRS costs would be assigned to all load-serving QSEs based upon their load ratio share without assessing any separate charge to those QSEs who under-scheduled capacity. If under-scheduling charges for capacity insufficient QSEs were not used to defray RPRS costs, REPS’s share of the total RPRS costs allocated to QSEs would increase.

Note 17 — 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 United States. 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 from 2010 through 2013 to meet NRG’s environmental commitments will be approximately $900 million and are primarily associated with controls on the Company’s Big Cajun and Indian River facilities. 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 U.S. EPA, 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 U.S. 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 CO₂ will 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 the 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 shoreline 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 is completed, the Company is unable to predict the impact of any required remediation.

On May 29, 2008, the DNREC requested that NRG’s Indian River Operations, Inc. 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 assessment phase.

South Central Region

On February 11, 2009, the U.S. Department of Justice acting at the request of the U.S. EPA commenced a lawsuit against Louisiana Generating, LLC in federal district court in the Middle District of Louisiana alleging violations of the CAA at the Big Cajun II power plant. This is the same matter for which NOVs were issued to Louisiana Generating, LLC on February 15, 2005, and on December 8, 2006. Further discussion on this matter can be found in Note 15, Commitments and Contingencies, to this Form 10-Q, Louisiana Generating, LLC.

Note 18 — 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, retail contracts, 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. The Company is also obligated with respect to customer deposits associated with Reliant Energy.

This Note 18 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 executed an agreement guaranteeing the performance of its subsidiary Lambique Beheer under the purchase and sale agreement. This agreement indemnifies the buyer for tax, environmental liability and other matters, as well as breaches of representations and warranties and is limited to EUR 206 million.

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 RRI in connection with the purchase of its retail business, including purchase price and acquired net working capital. In accordance with the LLC Membership Interest Purchase Agreement, on May 1, 2009, NRG signed an agreement guaranteeing payments up to $85 million related to the Restated Power Purchase Agreement with FPL Energy Upton Wind II, LLC. NRG has no reason to believe that the Company currently has any material liability relating to such routine indemnification obligations.

In connection with the October 5, 2009 amendment of the CSRA, NRG signed guarantee agreements on behalf of its subsidiary NRG Retail, LLC guaranteeing performance under power purchase and sales contracts. See Note 20, Subsequent Event, to this Form 10-Q for further discussion of the CSRA Amendment.

Note 19 — Condensed Consolidating Financial Information

As of September 30, 2009, the Company had outstanding $1.2 billion of 7.25% Senior Notes due 2014, $2.4 billion of 7.375% Senior Notes due 2016, $1.1 billion of 7.375% Senior Notes due 2017, and $700 million of 8.50% Senior Notes due 2019. The Senior Notes are guaranteed by certain of NRG’s current and future wholly-owned domestic subsidiaries, or guarantor subsidiaries. On October 5, 2009, RERH became a guarantor subsidiary as a result of the CSRA Amendment. See Note 20, Subsequent Event, to this Form 10-Q , for a discussion of the CSRA Amendment.

Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of September 30, 2009:


Arthur Kill Power LLC		NRG Devon Operations Inc.
Astoria Gas Turbine Power LLC		NRG Dunkirk Operations, Inc.
Berrians I Gas Turbine Power LLC		NRG El Segundo Operations Inc.
Big Cajun II Unit 4 LLC		NRG Generation Holdings, Inc.
Cabrillo Power I LLC		NRG Huntley Operations Inc.
Cabrillo Power II LLC		NRG International LLC
Chickahominy River Energy Corp.		NRG Kaufman LLC
Commonwealth Atlantic Power LLC		NRG Mesquite LLC
Conemaugh Power LLC		NRG MidAtlantic Affiliate Services Inc.
Connecticut Jet Power LLC		NRG Middletown Operations Inc.
Devon Power LLC		NRG Montville Operations Inc.
Dunkirk Power LLC		NRG New Jersey Energy Sales LLC
Eastern Sierra Energy Company		NRG New Roads Holdings LLC
El Segundo Power, LLC		NRG North Central Operations, Inc.
El Segundo Power II LLC		NRG Northeast Affiliate Services Inc.
GCP Funding Company LLC		NRG Norwalk Harbor Operations Inc.
Hanover Energy Company		NRG Operating Services Inc.
Hoffman Summit Wind Project LLC		NRG Oswego Harbor Power Operations Inc.
Huntley IGCC LLC		NRG Power Marketing LLC
Huntley Power LLC		NRG Rocky Road LLC
Indian River IGCC LLC		NRG Saguaro Operations Inc.
Indian River Operations Inc.		NRG South Central Affiliate Services Inc.
Indian River Power LLC		NRG South Central Generating LLC
James River Power LLC		NRG South Central Operations Inc.
Kaufman Cogen LP		NRG South Texas LP
Keystone Power LLC		NRG Texas LLC
Lake Erie Properties Inc.		NRG Texas C & I Supply LLC
Langford Wind Power, LLC		NRG Texas Holding Inc.
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		Reliant Energy Services Texas LLC
NEO Freehold-Gen LLC		Reliant Energy Texas Retail LLC
NEO Power Services Inc.		Saguaro Power LLC
New Genco GP LLC		San Juan Mesa Wind Project II, LLC
Norwalk Power LLC		Somerset Operations Inc.
NRG Affiliate Services Inc.		Somerset Power LLC
NRG Arthur Kill Operations Inc.		Texas Genco Financing Corp.
NRG Asia-Pacific Ltd.		Texas Genco GP, LLC
NRG Astoria Gas Turbine Operations Inc.		Texas Genco Holdings, Inc.
NRG Bayou Cove LLC		Texas Genco LP, LLC
NRG Cabrillo Power Operations Inc.		Texas Genco Operating Services, LLC
NRG Cadillac Operations Inc.		Texas Genco Services, LP
NRG California Peaker Operations LLC		Vienna Operations, Inc.
NRG Cedar Bayou Development Company LLC		Vienna Power LLC
NRG Connecticut Affiliate Services Inc.		WCP (Generation) Holdings LLC
NRG Construction LLC		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 September 30, 2009


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

Operating Revenues
Total operating revenues	$	1,216		$	1,854		$	(1	)	$	(153	)	$	2,916

Operating Costs and Expenses
Cost of operations		749			1,301			(1	)		(156	)		1,893
Depreciation and amortization		160			51			1			—			212
Selling, general and administrative		16			78			88			—			182
Acquisition-related transaction and integration costs		—			—			6			—			6
Development costs		1			1			10			—			12

Total operating costs and expenses		926			1,431			104			(156	)		2,305

Operating Income/(Loss)		290			423			(105	)		3			611
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries		—			—			592			(592	)		—
Equity in earnings of unconsolidated affiliates		3			3			—			—			6
Other income/(loss), net		2			2			4			(3	)		5
Interest expense		(5	)		(38	)		(135	)		—			(178	)

Total other (expense)/income		—			(33	)		461			(595	)		(167	)

Income/(Losses) Before Income Taxes		290			390			356			(592	)		444
Income tax expense/(benefit)		(51	)		139			78			—			166

Net Income/(Loss)		341			251			278			(592	)		278
Less: Net loss attributable to noncontrolling interest		—			—			—			—			—

Net Income/(Loss) attributable to NRG Energy, Inc.	$	341		$	251		$	278		$	(592	)	$	278


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

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Nine Months Ended September 30, 2009


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

Operating Revenues
Total operating revenues	$	3,807		$	3,203		$	31		$	(230	)	$	6,811

Operating Costs and Expenses
Cost of operations		2,043			2,088			3			(233	)		3,901
Depreciation and amortization		475			115			4			—			594
Selling general and administrative		50			132			214			—			396
Acquisition-related transaction and integration costs		—			—			41			—			41
Development costs		5			6			23			—			34

Total operating costs and expenses		2,573			2,341			285			(233	)		4,966

Operating Income/(Loss)		1,234			862			(254	)		3			1,845
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries		129			—			1,466			(1,595	)		—
Equity in earnings of unconsolidated affiliates		7			26			—			—			33
Gain on sale of equity method investment		—			128			—			—			128
Other income/(loss), net		5			(17	)		6			(3	)		(9	)
Interest expense		(71	)		(97	)		(307	)		—			(475	)

Total other income/(expense)		70			40			1,165			(1,598	)		(323	)

Income/(Losses) Before Income Taxes		1,304			902			911			(1,595	)		1,522
Income tax expense		298			314			2			—			614

Net Income/(Loss)		1,006			588			909			(1,595	)		908
Less: Net loss attributable to noncontrolling interest		(1	)		—			—			—			(1	)

Net Income/(Loss) attributable to NRG Energy, Inc.	$	1,007		$	588		$	909		$	(1,595	)	$	909


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

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
September 30, 2009


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

ASSETS

Current Assets
Cash and cash equivalents	$	11		$	418	$	1,821	$	—		$	2,250
Funds deposited by counterparties		293			—		—		—			293
Restricted cash		1			25		—		—			26
Accounts receivable, net		355			764		—		—			1,119
Inventory		518			15		—		—			533
Derivative instruments valuation		2,517			1,010		—		(328	)		3,199
Deferred income taxes		(489	)		248		342		—			101
Cash collateral paid in support of energy risk management activities		222			253		—		—			475
Prepayments and other current assets		166			71		243		(265	)		215

Total current assets		3,594			2,804		2,406		(593	)		8,211

Net property, plant and equipment		10,597			970		43		—			11,610

Other Assets
Investment in subsidiaries		530			221		16,955		(17,706	)		—
Equity investments in affiliates		35			357		—		—			392
Capital leases and notes receivable, less current portion		4,621			507		3,018		(7,639	)		507
Goodwill		1,718			—		—		—			1,718
Intangible assets, net		795			1,145		33		(31	)		1,942
Nuclear decommissioning trust fund		354			—		—		—			354
Derivative instruments valuation		795			460		9		(225	)		1,039
Other non-current assets		37			9		135		—			181

Total other assets		8,885			2,699		20,150		(25,601	)		6,133

Total Assets	$	23,076		$	6,473	$	22,599	$	(26,194	)	$	25,954

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	67		$	505	$	32	$	(67	)	$	537
Accounts payable		(625	)		1,111		239		—			725
Derivative instruments valuation		1,971			1,370		4		(328	)		3,017
Cash collateral received in support of energy risk management activities		293			—		—		—			293
Accrued expenses and other current liabilities		270			273		291		(198	)		636

Total current liabilities		1,976			3,259		566		(593	)		5,208

Other Liabilities
Long-term debt and capital leases		2,580			890		12,398		(7,639	)		8,229
Nuclear decommissioning reserve		296			—		—		—			296
Nuclear decommissioning trust liability		249			—		—		—			249
Deferred income taxes		670			111		791		—			1,572
Derivative instruments valuation		315			679		90		(225	)		859
Out-of-market contracts		229			126		—		(31	)		324
Other non-current liabilities		425			26		687		—			1,138

Total non-current liabilities		4,764			1,832		13,966		(7,895	)		12,667

Total liabilities		6,740			5,091		14,532		(8,488	)		17,875

3.625% Preferred Stock		—			—		247		—			247
Stockholders’ Equity		16,336			1,382		7,820		(17,706	)		7,832

Total Liabilities and Stockholders’ Equity	$	23,076		$	6,473	$	22,599	$	(26,194	)	$	25,954


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

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2009


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

Cash Flows from Operating Activities
Net income	$	1,006		$	588		$	909		$	(1,595	)	$	908
Adjustments to reconcile net income to net cash provided by operating activities:
Distributions and equity in (earnings)/losses of unconsolidated affiliates and consolidated subsidiaries		194			(26	)		(1,136	)		935			(33	)
Depreciation and amortization		475			115			4			—			594
Provision for bad debts		—			37			—			—			37
Amortization of nuclear fuel		28			—			—			—			28
Amortization of financing costs and debt discount/premiums		—			11			24			—			35
Amortization of intangibles and out-of-market contracts		(65	)		144			—			—			79
Changes in deferred income taxes and liability for unrecognized tax benefits		(46	)		6			601			—			561
Changes in nuclear decommissioning liability		19			—			—			—			19
Changes in derivatives		(32	)		(202	)		—			—			(234	)
Changes in collateral deposits supporting energy risk management activities		266			(253	)		—			—			13
Loss on sale of assets		2			—			—			—			2
Gain on sale of equity method investment		—			(128	)		—			—			(128	)
Gain on sale of emission allowances		(8	)		—			—			—			(8	)
Gain recognized on settlement of pre-existing relationship		—			—			(31	)		—			(31	)
Amortization of unearned equity compensation		—			—			20			—			20
Changes in option premiums collected		(266	)		(12	)		—			—			(278	)
Cash provided by/(used by) changes in other working capital		614			248			(1,166	)		—			(304	)

Net Cash Provided/(Used) by Operating Activities		2,187			528			(775	)		(660	)		1,280

Cash Flows from Investing Activities
Intercompany (loans to)/receipts from subsidiaries		(1,395	)		—			159			1,236			—
Acquisition of Reliant Energy, net of cash acquired		—			(68	)		(288	)		—			(356	)
Investment in Reliant Energy		—			200			(200	)		—			—
Capital expenditures		(409	)		(149	)		(2	)		—			(560	)
(Increase)/decrease in restricted cash, net		6			(16	)		—			—			(10	)
Decrease/(increase) in notes receivable		—			(53	)		35			—			(18	)
Purchases of emission allowances		(68	)		—			—			—			(68	)
Proceeds from sale of emission allowances		20			—			—			—			20
Investments in nuclear decommissioning trust fund securities		(237	)		—			—			—			(237	)
Proceeds from sales of nuclear decommissioning trust fund securities		218			—			—			—			218
Proceeds from sale of assets, net		6			—			—			—			6
Other investment		(1	)		—			(5	)		—			(6	)
Proceeds from sale of equity method investment		—			284			—			—			284

Net Cash (Used)/Provided by Investing Activities		(1,860	)		198			(301	)		1,236			(727	)

Cash Flows from Financing Activities
Proceeds from intercompany loans		(188	)		29			1,395			(1,236	)		—
Payment from intercompany dividends		(330	)		(330	)		—			660			—
Payment of dividends to preferred stockholders		—			—			(27	)		—			(27	)
Net payments to settle acquired derivatives that include financing elements		166			(306	)		—			—			(140	)
Payment for treasury stock		—			—			(250	)		—			(250	)
Proceeds from issuance of common stock, net of issuance costs		—			—			1			—			1
Installment proceeds from sale of noncontrolling interest in subsidiary		—			50			—			—			50
Proceeds from issuance of long-term debt		38			116			689			—			843
Payment of deferred debt issuance costs		—			(2	)		(27	)		—			(29	)
Payment of short and long-term debt		—			(27	)		(221	)		—			(248	)

Net Cash (Used)/Provided by Financing Activities		(314	)		(470	)		1,560			(576	)		200
Effect of exchange rate changes on cash and cash equivalents		—			3			—			—			3

Net Increase in Cash and Cash Equivalents		13			259			484			—			756
Cash and Cash Equivalents at Beginning of Period		(2	)		159			1,337			—			1,494

Cash and Cash Equivalents at End of Period	$	11		$	418		$	1,821		$	—		$	2,250


(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 September 30, 2008


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

Operating Revenues
Total operating revenues	$	2,519		$	111		$	—		$	(18	)	$	2,612

Operating Costs and Expenses
Cost of operations		919			99			(3	)		(18	)		997
Depreciation and amortization		148			7			1			—			156
General and administrative		16			14			45			—			75
Development costs		2			2			9			—			13

Total operating costs and expenses		1,085			122			52			(18	)		1,241

Operating Income/(Loss)		1,434			(11	)		(52	)		—			1,371
Other Income/(Expense)
Equity in earnings/(losses) of consolidated subsidiaries		52			50			868			(970	)		—
Equity in earnings of unconsolidated affiliates		1			57			—			—			58
Other income/(loss), net		4			11			(22	)		—			(7	)
Interest expense		(46	)		(17	)		(79	)		—			(142	)

Total other income/(expense)		11			101			767			(970	)		(91	)

Income/(Loss) From Continuing Operations Before Income Taxes		1,445			90			715			(970	)		1,280
Income tax expense/(benefit)		527			38			(63	)		—			502

Income/(Loss) From Continuing Operations		918			52			778			(970	)		778
Net Income/(Loss) attributable to NRG Energy, Inc.	$	918		$	52		$	778		$	(970	)	$	778


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

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Nine Months Ended September 30, 2008


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

Operating Revenues
Total operating revenues	$	4,942		$	306		$	—		$	(18	)	$	5,230

Operating Costs and Expenses
Cost of operations		2,600			231			—			(19	)		2,812
Depreciation and amortization		454			21			3			—			478
General and administrative		47			10			176			—			233
Development costs		(3	)		5			27			—			29

Total operating costs and expenses		3,098			267			206			(19	)		3,552

Operating Income/(Loss)		1,844			39			(206	)		1			1,678
Other Income/(Expense)
Equity in earnings/(losses) of consolidated subsidiaries		262			—			1,313			(1,575	)		—
Equity in (losses)/earnings of unconsolidated affiliates		(2	)		37			—			—			35
Other income/(loss), net		19			10			(14	)		(1	)		14
Interest expense		(148	)		(56	)		(238	)		—			(442	)

Total other income/(expense)		131			(9	)		1,061			(1,576	)		(393	)

Income/(Loss) From Continuing Operations Before Income Taxes		1,975			30			855			(1,575	)		1,285
Income tax expense/(benefit)		694			5			(196	)		—			503

Income/(Loss) From Continuing Operations		1,281			25			1,051			(1,575	)		782
Income/(loss) from discontinued operations, net of income taxes		—			269			(97	)		—			172

Net Income/(Loss) attributable to NRG Energy, Inc.	$	1,281		$	294		$	954		$	(1,575	)	$	954

(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 Nine Months Ended September 30, 2008


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

Cash Flows from Operating Activities
Net income	$	1,281		$	294		$	954		$	(1,575	)	$	954
Adjustments to reconcile net income to net cash provided by operating activities
Distributions and equity (earnings)/losses of unconsolidated affiliates and consolidated subsidiaries		(260	)		(26	)		(1,313	)		1,575			(24	)
Depreciation and amortization		454			21			3			—			478
Amortization of nuclear fuel		31			—			—			—			31
Amortization of financing costs and debt discount/ premiums		—			11			17			—			28
Amortization of intangibles and out-of-market contracts		(226	)		—			—			—			(226	)
Changes in deferred income taxes and liability for unrecognized tax benefits		102			(21	)		358			—			439
Changes in nuclear decommissioning liability		8			—			—			—			8
Changes in derivatives		(135	)		(9	)		—			—			(144	)

Changes in collateral deposits supporting energy risk management activities		(320	)		—			—			—			(320	)
Loss on sale of assets		13			—			—			—			13
Gain on sale of discontinued operations		—			(273	)		—			—			(273	)
Gain on sale of emission allowances		(52	)		—			—			—			(52	)
Amortization of unearned equity compensation		—			—			21			—			21
Changes in option premiums collected		203			—			—			—			203
Cash provided by/(used by) changes in other working capital		377			52			(479	)		—			(50	)

Net Cash Provided by/(Used) by Operating Activities		1,476			49			(439	)		—			1,086

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

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

Cash Flows from Financing Activities
(Payments)/proceeds for intercompany loans		(882	)		208			(36	)		710			—
Payments for dividends to preferred stockholders		—			—			(41	)		—			(41	)
Net payments to settle acquired derivatives that include financing elements		(49	)		—			—			—			(49	)
Payment for CSF I CAGR settlement		—			(45	)		—			—			(45	)
Payments for treasury stock		—			—			(185	)		—			(185	)
Proceeds from issuance of common stock, net of issuance costs		—			—			8			—			8
Installment proceeds from sale of noncontrolling interest on subsidiary		—			50			—			—			50
Proceeds from issuance of long-term debt		—			20			—			—			20
Payments for deferred debt issuance costs		—			—			(2	)		—			(2	)
Payments for short and long-term debt		—			(36	)		(166	)		—			(202	)

Net Cash (Used)/Provided by Financing Activities		(931	)		197			(422	)		710			(446	)
Change in cash from discontinued operations		—			43			—			—			43
Effect of exchange rate changes on cash and cash equivalents		—			—			—			—			—

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

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

(a)

All significant intercompany transactions have been eliminated in consolidation.

Note 20 — Subsequent Event

Unwind of the Merrill Lynch Credit Sleeve

The Company executed an amendment of the existing CSRA with Merrill Lynch, or CSRA Amendment, which became effective October 5, 2009. The CSRA Amendment removed the first liens associated with the CSRA, and RERH subsequently became a guarantor of the Company’s obligations under its Senior Notes. See Note 19, Condensed Consolidating Financial Information, to this Form 10-Q for further discussion of NRG’s guarantees under its Senior Notes.

In connection with the CSRA Amendment, NRG net settled or offset certain REPS transactions with counterparties and received $165 million in net cash consideration. Merrill Lynch returned $250 million of previously posted cash collateral and released liens on $322 million of unrestricted cash held at Reliant Energy.

Pursuant to the CSRA Amendment, the Company was required to post collateral for any net liability derivatives and other static margin associated with supply for Reliant Energy. In connection with this transaction, NRG posted $366 million of cash collateral to Merrill Lynch and other counterparties, returned $53 million of counterparty collateral, issued letters of credit of $206 million, and received $45 million in counterparty collateral. The funds posted by the Company were sourced from a portion of the proceeds from the June 5, 2009 issuance of the 2019 Senior Notes. See Note 8, Long-Term Debt, to this Form 10-Q, for further discussion of the 2019 Senior Notes. In addition, $25 million outstanding under NRG’s $50 million working capital facility with Merrill Lynch was repaid, and the facility was terminated. See Note 4, Business Acquisition, to this Form 10-Q, for further discussion of the working capital facility entered into on May 1, 2009.

NRG has also paid Merrill Lynch $5 million in connection with the CSRA Amendment, and will make a second payment of $5 million on January 4, 2010. Merrill Lynch has terminated NRG’s contingent equity obligations under the previous credit sleeve. The parties have agreed to settle any outstanding wholesale obligations under the CSRA Amendment by January 29, 2010, and any C&I related Merrill Lynch obligations by April 30, 2010.

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 and nine months ended September 30, 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 Energy acquisition and the disposition of the MIBRAG investment.

Executive Summary

Introduction and Overview

As of September 30, 2009, NRG had a total global generation portfolio of 187 active operating fossil fuel and nuclear generation units, at 46 power generation plants, with an aggregate generation capacity of approximately 24,100 MW, and approximately 550 MW under construction which includes partners’ interests of 200 MW. In addition to its fossil fuel plant ownership, NRG has ownership interests in two operating wind farms representing an aggregate generation capacity of 270 MW, which includes partner interests of 75 MW. Within the U.S., NRG has one of the largest and most diversified power generation portfolios in terms of geography, fuel-type and dispatch levels, with approximately 23,095 MW of fossil fuel and nuclear generation capacity in 179 active generating units at 42 plants. The Company’s power generation facilities are most heavily concentrated in Texas (approximately 11,190 MW, including 195 MW from the two wind farms), the Northeast (approximately 7,015 MW), South Central (approximately 2,840 MW), and West (approximately 2,130 MW) regions of the U.S., 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 46%, 32%, 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.

On May 1, 2009, NRG acquired Reliant Energy, which is the second largest mass market electricity provider to residential and commercial customers in Texas. Based on metered locations, as of September 30, 2009, Reliant Energy had approximately 1.6 million Mass customers and approximately 0.1 million C&I customers. Reliant Energy arranges for the transmission and delivery of electricity to customers, bills customers, collects payments for electricity sold and maintains call centers to provide customer service.

NRG’s Business Strategy

NRG’s business strategy is intended to maximize shareholder value over time through the production and the sale of safe, reliable and affordable power to its customers and in the markets served by the Company, while aggressively pursuing sustainable energy solutions for the future. The key to successful implementation of this strategy is the Company’s sizable fleet of wholesale power generation assets in the U.S., its leading retail franchise in Texas and, increasingly, its position as an industry leader in the development of various types of low and no carbon generation technologies and integrated solutions aimed at satisfying the Company’s customers’ increasing demand for sustainable energy lifestyles. In addition, NRG utilizes 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. More specifically, 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; (iii) empowering retail customers with distinctive products and services that transform how they use, manage, and value energy; (iv) investment in energy-related new businesses and new technologies being developed and deployed in response to the twin societal dynamics to foster sustainability and combat climate change; and (v) engaging in a proactive capital allocation plan focused on achieving the regular return of capital to stockholders within the dictates of prudent balance sheet management. 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 enable the Company to convert the challenges faced by the power industry in the coming years into opportunities for financial growth. This strategy is being implemented by focusing on the following principles, which are more fully described in the 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 2.0 initiative, commercial operations strategy, achieving synergies between the Company’s retail and wholesale business in Texas, and maintaining of appropriate levels of liquidity, debt and equity in order to ensure continued access to capital through all economic and financial cycles.

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 some or all of the following benefits: improved heat rates; lower delivered costs; expanded electricity production capability; improved ability to dispatch economically across the regional general portfolio; increased technological and fuel diversity; and reduced environmental impacts, including facilities that either have near zero GHG emissions or can be equipped to capture and sequester GHG emissions. In addition, 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 and NRG has several applications pending or contemplated.

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 are expected to 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 Energy has put the Company in a position to consider and pursue sustainable energy lifestyles, such as smart meters, electric vehicle ecosystems, 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 address workforce planning and community involvement and support, 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.

Business Environment

Financial Credit Market Availability

Power generation companies are capital intensive and, as such, rely on the credit markets for liquidity and for the financing of power generation investments. During the first nine months of 2009, the nation’s credit markets have recovered to some extent although credit continued to be tight relative to years prior to 2008. As evidence of the markets’ improvement, in April 2009, GenConn Energy, a joint venture of NRG and the United Illuminating Company, closed on a $534 million project financing and NRG was able to issue $700 million of bonds in June 2009, with a 10 year maturity at a yield to maturity of 8.75%. NRG has a diversified liquidity program, with $3.9 billion in total liquidity as of September 30, 2009, 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 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.

The addition of Reliant Energy to NRG’s existing generation business may provide opportunities to match generation to load directly which should reduce hedging and credit costs that both businesses would incur if hedged separately. Reliant Energy, which expects to lock in its wholesale supply in order to secure its margin as load is contracted, should also benefit from having better access to nonstandard products necessary to meet load. NRG expects to continue hedging its wholesale production consistent with its prior practice, but now will benefit from having an additional outlet for its range of generation products.

Proposed Over-the-Counter Derivative Legislation

Congress is currently considering legislative proposals that would significantly increase the regulation of over-the-counter derivatives including those related to energy commodities, through the amendment of the Commodity Exchange Act. While NRG cannot predict at this time the outcome of any of the legislative efforts, many of the proposals generally contemplate mandatory clearing of such derivatives through clearing organizations and the increased standardization of contracts, products, and collateral requirements. Such changes could negatively impact NRG’s ability to hedge its portfolio in an efficient, cost-effective manner, and, among other things, may limit NRG’s ability to utilize liens as collateral. Such changes may also result in a decrease in liquidity in the commodity markets.

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. 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 recommended that NRG stockholders not tender their shares. In addition, on June 17, 2009, Exelon filed a Definitive Proxy Statement with the SEC with respect to their proposals for the Company’s 2009 Annual Meeting of Stockholders, which consisted of: (i) consideration of Exelon’s four nominees as Class III directors; (ii) consideration of the expansion of NRG’s Board of Directors to 19 directors; (iii) if the Exelon board expansion is approved, consideration of five additional Exelon nominees; and (iv) consideration of repealing any amendments to the NRG Bylaws after February 26, 2008. NRG’s Board of Directors recommended a vote against each of the proposals. On July 2, 2009, Exelon revised their unsolicited proposal and 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 recommended that NRG stockholders not tender their shares. On July 21, 2009, based on the preliminary vote count at NRG’s 2009 Annual Meeting of Stockholders, stockholders voted to re-elect all of the Company’s director nominees to the NRG Board of Directors. In addition, NRG’s stockholders rejected Exelon’s proposal to expand NRG’s Board with its own slate of five Director nominees. On July 21, 2009, Exelon Corporation announced that in light of the vote results, effective immediately, it terminated its offer to acquire all of the outstanding shares of NRG. On July 29, 2009, IVS Associates, Inc., the independent inspector of elections, certified the final results. The total defense costs associated with Exelon’s unsolicited proposal was approximately $39 million for the period October 1, 2008, through September 30, 2009, of which $31 million was for the nine months ended September 30, 2009.

Environmental Matters

Climate Change

Senators Kerry and Boxer introduced climate legislation based on The American Clean Energy and Security Act of 2009 which passed the House of Representatives in June 2009. The Senate bill proposes a multi-sector, market based greenhouse gas cap-and-trade system starting in 2012. It provides for a declining cap in U.S. GHG emissions and provides for the allocation of allowances to merchant coal generators, the use of both international and domestic offsets to local distribution companies , and a transition from already existing state programs, all of which are important to the electric generation industry. It proposes requirements for new coal-fueled power plants to implement, based on commercial availability, carbon capture and sequestration to reduce CO₂ emissions. NRG will continue to provide input as a leading energy company and member of the U.S. Climate Action Partnership, or USCAP, in support of federal legislation.

In 2008, NRG emitted 60 million metric tonnes of CO₂from its domestic operations. If climate change legislation or some other federal comprehensive climate change bill were to pass both Houses 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 24, 2009, the U.S. EPA published a proposed endangerment finding that stated that the mix of six key GHGs, including CO₂, threaten the public health and welfare. On September 28, 2009, U.S.EPA and Department of Transportation, or DOT published “Proposed GHG Emissions Standards for Motor Vehicles”. These actions are in response to the Supreme Court’s decision in Massachusetts v. U.S. EPA, which requires the U.S. EPA to decide under the CAA’s mobile source title whether GHGs contribute to climate change, and if so, promulgate appropriate regulations. Under the CAA, these regulations when final, would render GHGs regulated pollutants and subject them to other existing requirements that affect stationary sources, including power plants. The primary impact on NRG would be a statutory requirement to install BACT determined on a case-by-case basis, for major modifications or improvements at power plants if they cause GHG emissions to increase by the statutory Prevention of Significant Deterioration, or PSD limits of 100 tons per year. The U.S. EPA also released, on September 30, 2009, a draft PSD tailoring rule for GHGs that would increase the major stationary source threshold of 25,000 tons per year of carbon dioxide equivalents. This threshold level would be used to determine (i) if an existing source would be required to obtain a Title V operating permit and (ii) if a new facility or a major modification at an existing facility would trigger PSD permitting requirements. Existing major sources making modifications that result in an increase of emissions above the significance level would be required to obtain a PSD permit and install BACT. The timing of the final motor vehicle rule, acceptance of the PSD tailoring rule and EPA’s approach to BACT for GHGs could affect the level of impact to NRG’s plants and future repowering projects.

Federal Environmental Initiatives

A number of regulations are under review by U.S. EPA including CAIR, MACT, National Ambient Air Quality Standards, or NAAQS, for ozone, nitrogen dioxide, SO₂, 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 U.S. EPA 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’s planned environmental capital expenditures include 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 Phase II 316(b) Rule. NRG continues to explore cost-effective alternatives that can achieve desired results. This planned investment reflects anticipated schedules and controls related to CAIR, MACT for mercury, and the Phase II 316(B) Rule which are under remand to the U.S. EPA 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.

On April 24, 2009, the U.S. EPA granted petitions to reconsider three NSR rules; Fugitive Emissions, PM2.5 Implementation, and Reasonable Possibility. A Notice for reconsideration of the PM2.5 Implementation Rule was published in the Federal Register on May 1, 2009. While none of these actions directly impact NRG at this point, it is unknown if any such final rules will impact future projects.

The U.S. Supreme Court released its decision in the Phase II 316(b) Rule case on April 1, 2009, in which it concluded that the U.S. EPA 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 U.S. EPA’s ability to include alternatives to closed-loop cooling in its redraft of the Phase II 316(b) Rules. In the absence of federal regulations, some states in which NRG operates, such as California, Connecticut, Delaware and New York, are moving ahead with guidance for more stringent requirements for once through cooled units which may have an impact on future operations.

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 CO₂cap-and-trade program went into effect on January 1, 2009. An allowance must be surrendered for every U.S. ton of CO₂ emitted with true up for 2009-2011 occurring in 2012. NRG’s emissions under RGGI were approximately 12 million tonnes in 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. NRG is also subject to regulatory requirements as a competitive retail electric service provider in Texas. The 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.

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 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. The transmission expansion plan is composed of 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 the PUCT’s CREZ plan in state district court, seeking reversal of the final order. On March 30, 2009, the 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. In July of 2009, the PUCT approved schedules for utilities to file applications to license several of the CREZ transmission projects (to obtain certificates of convenience and necessity, or CCNs). If the CREZ projects are completed as currently anticipated, 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 in the ERCOT Region.

Changes in Accounting Standards

See Note 2, Summary of Significant Accounting Policies, to the condensed consolidated financial statements of this Form 10-Q as found in Item 1 for a discussion of recent accounting developments.

Consolidated Results of Operations

The following table provides selected financial information for the Company:


	Three months ended September 30,									Nine months ended September 30,
(In millions except otherwise noted)	2009			2008			Change %			2009			2008			Change %
Operating Revenues
Energy revenue	$	771		$	1,373			(44	)%	$	2,383		$	3,671			(35	)%
Capacity revenue		278			356			(22	)		791			1,037			(24	)
Retail revenue		1,876			—			N/A			3,126			—			N/A
Risk management activities		6			744			(99	)		431			27			N/A
Contract amortization		(60	)		76			(179	)		(92	)		233			(139	)
Thermal revenue		22			26			(15	)		77			85			(9	)
Other revenues		23			37			(38	)		95			177			(46	)

Total operating revenues		2,916			2,612			12			6,811			5,230			30
Operating Costs and Expenses
Cost of sales		1,628			780			109			3,256			2,133			53
Risk management activities		(16	)		—			N/A			(152	)		—			N/A
Other cost of operations		281			217			29			797			679			17

Total cost of operations		1,893			997			90			3,901			2,812			39
Depreciation and amortization		212			156			36			594			478			24
Selling, general and administrative		182			75			143			396			233			70
Acquisition-related transaction and integration costs		6			—			N/A			41			—			N/A
Development costs		12			13			(8	)		34			29			17

Total operating costs and expenses		2,305			1,241			86			4,966			3,552			40

Operating Income		611			1,371			(55	)		1,845			1,678			10
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates		6			58			(90	)		33			35			(6	)
Gain on sale of equity method investments		—			—			—			128			—			N/A
Other income/(loss), net		5			(7	)		171			(9	)		14			(164	)
Interest expense		(178	)		(142	)		25			(475	)		(442	)		7

Total other expense		(167	)		(91	)		84			(323	)		(393	)		(18	)

Income from Continuing Operations before income tax expense		444			1,280			(65	)		1,522			1,285			18
Income tax expense		166			502			(67	)		614			503			22

Income from Continuing Operations		278			778			(64	)		908			782			16
Income from discontinued operations, net of income taxes		—			—			—			—			172			N/A

Net Income		278			778			(64	)		908			954			(5	)

Less: Net loss attributable to noncontrolling interest		—			—			—			(1	)		—			N/A

Net income attributable to NRG Energy, Inc.	$	278		$	778			(64	)	$	909		$	954			(5	)

Business Metrics

Average natural gas price - Henry Hub ($/MMBtu)		3.15			9.11			(65	)%		3.80			9.67			(61	)%


N/A	—	Not Applicable

Management’s discussion of the results of operations for the three months ended September 30, 2009, and 2008:

For the benefit of the following discussions, the table below represents the results of NRG excluding the impact of Reliant Energy during the three months ended September 30, 2009:


	Three months ended September 30,
				2009						2008
							Total excluding
(In millions)	Consolidated			Reliant Energy			Reliant Energy			Consolidated		Change %

Operating Revenues
Energy revenue	$	771		$	—		$	771		$	1,373		(44	)%
Capacity revenue		278			—			278			356		(22	)
Retail revenue		1,876			1,876			—			—		—
Risk management activities		6			(1	)		7			744		(99	)
Contract amortization		(60	)		(85	)		25			76		(67	)
Thermal revenue		22			—			22			26		(15	)
Other revenues		23			—			23			37		(38	)

Total operating revenues		2,916			1,790			1,126			2,612		(57	)
Operating Costs and Expenses
Cost of sales		1,628			1,203			425			780		(46	)
Risk management activities		(16	)		—			(16	)		—		N/A
Other operating costs		281			60			221			217		2

Total cost of operations		1,893			1,263			630			997		(37	)
Depreciation and amortization		212			42			170			156		9
Selling, general and administrative		182			76			106			75		41
Acquisition-related transaction and integration costs		6			—			6			—		N/A
Development costs		12			—			12			13		(8	)

Total operating costs and expenses		2,305			1,381			924			1,241		(26	)

Operating Income	$	611		$	409		$	202		$	1,371		(85	)%

Operating Revenues

Operating revenues, excluding risk management activities, increased by $1.0 billion during the three months ended September 30, 2009, compared to the same period in 2008.

	•		Retail revenue — the acquisition of Reliant Energy contributed $1.9 billion of retail revenue during the three months ended September 30, 2009. Retail revenue includes mass revenues of $1.2 billion, C&I revenues of $620 million, and supply management revenues of $99 million.

	•		Energy revenue — decreased $602 million during the three months ended September 30, 2009, compared to the same period in 2008:

	o		Texas — energy revenue decreased by $201 million, with $177 million of the decrease driven by lower energy prices and $24 million of the decrease driven by a reduction in generation. The average realized energy price decreased by 21%, driven by a 53% decrease in merchant prices offset by a 21% increase in contract prices. Generation decreased by 3% driven by an 11% decrease in coal plant generation and an 8% decrease in nuclear plant generation, offset by a 47% increase in gas plant generation, as well as generation from the recently constructed Cedar Bayou 4 gas plant and Elbow Creek wind farm, which was not in operation in 2008. Coal plant generation was adversely affected by lower energy prices driven by a 64% decrease in average natural gas prices.

	o		Northeast — energy revenue decreased by $201 million, with $120 million driven by lower energy prices and $99 million attributable to a reduction in generation offset by an $18 million increase from higher net contract revenue. Average merchant energy prices were lower by 52%. The lower energy prices reduced the Company’s net cost incurred to meet obligations under load serving contracts in the PJM market. Generation decreased by 30% with a 34% decrease in coal generation and a 9% decrease in oil and gas generation. Weakened demand for power combined with lower gas prices resulting in reduced merchant energy prices. Lower merchant energy prices combined with higher costs of production from the introduction of RGGI resulting in increased hours where the coal plants were uneconomical to dispatch.

South Central — energy revenue decreased by $55 million due to a $24 million decline in contract revenue coupled with a decrease of $31 million in merchant energy revenues. The decline in contract energy price was driven by a $7 million decrease in fuel cost pass through from the cooperatives and a $17 million decrease due to the expiration of a contract with a regional utility. Total MWh sales to the region’s contract customers were down 7% while the average realized price on contract energy sales was $22.83 per MWh in 2009 compared to $29.19 per MWh in 2008. The expiration of the contract allowed more energy to be sold into the merchant market, but at lower average prices resulting in a $31 million decline in revenue. Megawatt hours sold to the merchant market increased by 18% as increased use of the region’s tolled facility provided additional energy to the merchant market while prices fell by 61%.

Intercompany energy revenue — intercompany sales of $144 million by the Company’s Texas region to Reliant Energy were eliminated in consolidation.

•

Capacity revenue — decreased $78 million during the three months ended September 30, 2009, compared to the same period in 2008:

	o		Texas — capacity revenue decreased by $79 million due to a lower proportion of baseload contracts which contained a capacity component.

	o		South Central — capacity revenue increased by a $12 million primarily resulting from a new capacity agreement.

	o		Intercompany capacity revenue — intercompany sales of $18 million by the Company’s Texas region to Reliant Energy were eliminated in consolidation.

	•		Contract amortization revenue — decreased by $136 million in the three months ended September 30, 2009, as compared to the same period in 2008. The decrease includes $85 million in amortization expense of net in-market C&I contracts related to the Reliant Energy acquisition in 2009 and a reduction of $52 million in revenue from the Texas Genco acquisition due to the lower volume of contracted energy.

	•		Other revenues — decreased by $14 million driven by $15 million in lower ancillary revenue and $13 million in lower emissions revenues. These decreases were offset by a $12 million increase in fuels trading.

Cost of Operations

Cost of operations, excluding risk management activities, increased $912 million during the three months ended September 30, 2009, compared to the same period in 2008.

•

Cost of sales — increased $848 million during the three months ended September 30, 2009, compared to the same period in 2008 due to:

	o		Retail — Reliant Energy incurred $1.2 billion of cost of energy during the three months ended September 30, 2009. Supply costs were $837 million which included $162 million of intercompany supply costs. Transmission and distribution charges totaled $392 million for the period. These costs were offset by $11 million of contract amortization for net out-of-market supply contracts.

	o		Texas — cost of energy decreased $81 million due to lower natural gas and coal costs. Natural gas costs decreased $84 million, reflecting a 64% decline in average natural gas per MMBtu prices offset by a 47% increase in gas-fired generation. Coal costs decreased $7 million due to 11% lower generation. In addition, a $19 million decrease in ancillary service costs was offset by a $13 million increase in purchased energy and other fuel costs.

	o		Northeast — cost of energy decreased $86 million due to a $53 million reduction in natural gas and oil costs and a $39 million reduction in coal costs. Natural gas and oil costs decreased due to 67% lower average natural gas prices and 9% lower generation. Coal costs decreased by $33 million due to 34% lower coal generation and by $6 million due to lower prices. These decreases were offset by a $6 million increase in costs related to RGGI which became effective in 2009.

	o		South Central — cost of energy decreased $52 million primarily due to a $35 million decrease in purchased energy reflecting lower fuel costs associated with energy from the region’s tolled facility and a $14 million decrease in natural gas costs reflecting 88% lower generation and 61% lower average gas prices.

	o		Intercompany cost of sales — intercompany purchases of $162 million by Reliant Energy from the Company’s Texas region is eliminated in consolidation.

•

Other cost of operations — increased $64 million during the three months ended September 30, 2009, compared to the same period in 2008. Reliant Energy incurred $37 million related to customer service operations and $24 million in gross receipt tax on revenue.

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 decreased by $722 million during the three months ended September 30, 2009, compared to the same period in 2008. The breakdown of changes by region follows:


	Three months ended September 30, 2009
	Reliant									South
(In millions)	Energy			Texas			Northeast			Central			West			Thermal		Elimination			Total

Net gains/(losses) on settled positions, or financial income in revenues	$	—		$	116		$	118		$	(2	)	$	(3	)	$	2	$	(8	)	$	223

Mark-to-market results in revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges		—			(4	)		(27	)		—			1			—		—			(30	)
Reversal of gain positions acquired as part of the Reliant Energy acquisition as of May 1, 2009		(1	)		—			—			—			—			—		—			(1	)
Reversal of previously recognized unrealized gains on settled positions related to trading activity		—			(8	)		(4	)		(9	)		—			—		—			(21	)
Net unrealized gains/(losses) on open positions related to economic hedges		—			(95	)		(70	)		—			(7	)		1		15			(156	)
Net unrealized gains/(losses) on open positions related to trading activity		—			5			2			(16	)		—			—		—			(9	)

Subtotal mark-to-market results		(1	)		(102	)		(99	)		(25	)		(6	)		1		15			(217	)

Total derivative gain/(loss) included in revenues	$	(1	)	$	14		$	19		$	(27	)	$	(9	)	$	3	$	7		$	6


	Three months ended September 30, 2009
	Reliant									South
(In millions)	Energy			Texas			Northeast			Central			Elimination			Total

Net gains/(losses) on settled positions, or financial expense in cost of operations	$	(202	)	$	(4	)	$	(1	)	$	(1	)	$	21		$	(187	)

Mark-to-market results in cost of operations
Reversal of previously recognized unrealized losses on settled positions related to economic hedges		—			11			20			—			—			31
Reversal of loss positions acquired as part of the Reliant Energy acquisition as of May 1, 2009		239			—			—			—			—			239
Net unrealized gains/(losses) on open positions related to economic hedges		(21	)		(18	)		3			(16	)		(15	)		(67	)

Subtotal mark-to-market results		218			(7	)		23			(16	)		(15	)		203

Total derivative gain/(loss) included in cost of operations	$	16		$	(11	)	$	22		$	(17	)	$	6		$	16


	Three months ended September 30, 2008
							South
(In millions)	Texas			Northeast			Central			Total

Net losses on settled positions, or financial income	$	(44	)	$	(43	)	$	(4	)	$	(91	)

Mark-to-market results
Reversal of previously recognized unrealized gains on settled positions related to economic hedges		(5	)		(2	)		—			(7	)
Reversal of previously recognized unrealized gains on settled positions related to trading activity		—			(6	)		(3	)		(9	)
Net unrealized gains on open positions related to economic hedges		590			201			—			791
Net unrealized gains on open positions related to trading activity		11			18			31			60

Subtotal mark-to-market results		596			211			28			835

Total derivative gain included in revenue		552			168			24			744

Total derivative gain included in cost of operations	$	—		$	—		$	—		$	—

NRG’s third quarter 2009 net gain of $22 million was comprised of $14 million of mark-to-market losses and $36 million in settled gains. Of the $14 million of mark-to-market losses, there was a loss of $217 million in revenue and a gain of $203 million in expense. The $217 million loss in revenue included a $51 million loss from the reversal of mark-to-market gains recognized during 2008 and loss of $165 million due to the decrease in value of forward purchases and sales of electricity and fuel due to higher forward power and gas prices. The $203 million of mark-to-market gains in expense included a gain of $31 million from the reversal of mark-to-market losses recognized during 2008, a $67 million loss due to the decrease in value of forward purchases and sales of electricity and fuel due to higher forward power and gas prices, and a $239 million from the roll-off of Reliant Energy loss positions. The Reliant Energy loss positions were acquired as of May 1, 2009 and valued using forward prices on that date. The $239 million roll-off amounts were offset by realized losses at settled prices and are reflected in the cost of operations during the same period.

NRG’s third quarter 2008 net gain of $744 million was comprised of mark-to-market gains of $835 million and $91 million in settled losses, or financial income. The realized losses were primarily driven by increases in settled power and gas prices. The mark-to-market gains were primarily driven by decreases in forward power and gas prices, and gains from a reduction in hedge accounting ineffectiveness.

Since these hedging activities are intended to mitigate the risk of commodity price movements on revenues and cost of operations, 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 2009, NRG hedged a portion of the Company’s 2008 and 2009 generation. During the third quarter 2009, the settled prices of electricity and natural gas decreased resulting in the recognition of realized gains while the forward prices of electricity and natural gas increased resulting in the recognition of unrealized mark-to-market losses. During the third quarter 2008, the settled prices for power and gas increased resulting in the recognition of realized losses while decreasing forward prices of electricity and natural gas resulted in recognition of unrealized mark-to-market gains.

The following table represents the results of the Company’s financial and physical trading of energy commodities for the three months ended September 30, 2009 and 2008. The realized financial trading results and unrealized financial and physical trading results are included in the risk management activities above, while the realized physical trading results are included in energy revenue.


	Three months ended
	September 30,
(In millions)	2009			2008

Trading gains/(losses)
Realized	$	27		$	13
Unrealized		(30	)		52

Total trading gains/(losses)		(3	)		65

Depreciation and Amortization

NRG’s depreciation and amortization expense increased by $56 million for the three months ended September 30, 2009, compared to the same period in 2008. Reliant Energy’s depreciation and amortization expense for the three month period was $42 million principally for amortization of customer relationships. The balance of the increase was due to depreciation on the baghouse projects in western New York and the Elbow Creek project which came online in late 2008, and the Cedar Bayou 4 project which came online in the second quarter 2009.

Selling, General and Administrative Expenses

Selling, general and administrative expenses increased by $107 million for the three months ended September 30, 2009, compared to the same period in 2008. The increase was due to:

	•		Retail selling, general and administrative expense — totaled $76 million, including $28 million of bad debt expense incurred during the three months ended September 30, 2009.

	•		Consultant costs — increased $18 million consisting of non-recurring costs related to Exelon’s exchange offer and proxy contest efforts of $21 million offset by a decrease in other consulting costs of $3 million.

	•		Wage and benefits expense — increased $13 million.

Acquisition-Related Transaction and Integration Costs

NRG incurred Reliant Energy acquisition-related transaction costs of $2 million and integration costs of $4 million for the three months ended September 30, 2009.

Equity in Earnings of Unconsolidated Affiliates

NRG’s equity earnings from unconsolidated affiliates decreased by $52 million for the three months ended September 30, 2009, compared to the same period in 2008. During the three months ended September 30, 2009, there was no equity earnings from the Sherbino I Wind Farm LLC, or Sherbino, investment. In the three months ended September 30, 2008, Sherbino recognized a $40 million mark-to-market gain on a natural gas swap executed to hedge its future power generation. Additionally, in 2009, the Company’s share in its former MIBRAG investments and Gladstone Power Station decreased $10 million and $4 million, respectively, while the Company’s share in NRG Saguaro LLC earnings increased by $2 million.

Other Income/(Loss), Net

NRG’s other income/(loss), net increased $12 million for the three months ended September 30, 2009, compared to the same period in 2008. The 2009 interest income was lower compared to 2008 due to reduced interest rates. The effect of lower interest income in 2009 was offset by the effect of $19 million impairment charge in 2008 to restructure distressed investments in commercial paper.

Interest Expense

NRG’s interest expense increased by $36 million for the three months ended September 30, 2009, compared to the same period in 2008. This increase was primarily due to a $15 million increase in fees incurred on the CSRA facility which began in May 2009, a $15 million increase in interest expense as a result of the 2019 Senior Notes issued in June 2009, a $4 million increase related to ineffective portion of the interest rate cash flow hedge on the Company’s Term Loan Facility and a $5 million increase in the amortization of deferred financing costs. These increases were offset by a $7 million decrease in interest expense on the Company’s Term Loan Facility due to a decrease in the outstanding notional amount and lower interest rates related to the unhedged portion of the Term Loan and fair value portion of the Senior Notes.

Income Tax Expense

NRG’s income tax expense decreased by $336 million for the three months ended September 30, 2009, compared to the same period in 2008. The decrease in income tax expense was primarily due to a decrease in income. The effective tax rate was 37.4% and 39.2% for the three months ended September 30, 2009, and 2008, respectively.

Management’s discussion of the results of operations for the nine months ended September 30, 2009, and 2008:

For the benefit of the following discussions, the table below represents the results of NRG excluding the impact of Reliant Energy during the nine months ended September 30, 2009:


	Nine months ended September 30,
				2009					2008
							Total excluding
(In millions)	Consolidated			Reliant Energy			Reliant Energy		Consolidated		Change %

Operating Revenues
Energy revenue	$	2,383		$	—		$	2,383	$	3,671		(35	)%
Capacity revenue		791			—			791		1,037		(24	)
Retail revenue		3,126			3,126			—		—		—
Risk management activities		431			(1	)		432		27		N/A
Contract amortization		(92	)		(160	)		68		233		(71	)
Thermal revenue		77			—			77		85		(9	)
Other revenues		95			—			95		177		(46	)

Total operating revenues		6,811			2,965			3,846		5,230		(26	)
Operating Costs and Expenses
Cost of sales		3,256			2,022			1,234		2,133		(42	)
Risk management activities		(152	)		(205	)		53		—		N/A
Other operating costs		797			101			696		679		3

Total cost of operations		3,901			1,918			1,983		2,812		(29	)
Depreciation and amortization		594			85			509		478		6
Selling, general and administrative		396			125			271		233		16
Acquisition-related transaction and integration costs		41			—			41		—		N/A
Development costs		34			—			34		29		17

Total operating costs and expenses		4,966			2,128			2,838		3,552		(20	)

Operating Income	$	1,845		$	837		$	1,008	$	1,678		(40	)%

Operating Revenues

Operating revenues, excluding risk management activities, increased $1.2 billion during the nine months ended September 30, 2009, compared to the same period in 2008.

	•		Retail revenue — the acquisition of Reliant Energy contributed $3.1 billion of retail revenue during the five months ended September 30, 2009. Retail revenue includes mass revenues of $1.9 billion, C&I revenues of $1.1 billion, and supply management revenues of $151 million.

	•		Energy revenue — decreased $1.3 billion during the nine months ended September 30, 2009, compared to the same period in 2008:

	o		Texas — energy revenue decreased by $478 million, with $373 million driven by lower average realized energy prices and a $105 million decrease driven by a reduction in generation. The average realized energy price decreased by 17%, driven by a 52% decrease in merchant prices, offset by a 23% increase in contract prices. Lower merchant prices were driven by the combination of lower gas prices in 2009 and unusually high pricing events that occurred in 2008 that did not repeat in 2009. Generation decreased by 5% driven by a 9% decrease in coal plant generation offset by a 6% increase in gas plant generation, and generation from the recently constructed Cedar Bayou 4 gas plant and Elbow Creek wind farm, which was not in operation in 2008. Coal plant generation was adversely affected by lower energy prices driven by a 66% decrease in average natural gas prices in combination with increased wind generation which shifted the coal unit’s position in the bid stack, negatively affecting coal plant generation.

	o		Northeast — energy revenue decreased by $490 million, with $231 million driven by lower energy prices and $312 million attributable to a reduction in generation offset by a $53 million increase from higher net contract revenue. Merchant energy prices were lower by an average of 40%. The lower energy prices reduced the Company’s net cost incurred to meet obligations under load serving contracts in the PJM market. Generation decreased by 35%, with a 36% decrease in coal generation and a 28% decrease in oil and gas generation. Weakened demand for power combined with lower gas prices resulted in reduced merchant energy prices. Lower merchant energy prices combined with higher costs of production from the introduction of RGGI resulted in increased hours where the coal plants were uneconomical to dispatch. The decline in oil and gas generation is attributable to fewer reliability run hours at the Connecticut plants.

	o		South Central — decreased by $108 million due to a $66 million decline in contract revenue coupled with a $42 million decrease in merchant energy revenues. Contract customer sales volumes were down 10%. The decline in contract energy price was driven by a $12 million decrease in fuel cost pass through to the cooperatives. Also contributing to the decline in contract revenue was $48 million due to the expiration of a contract with a regional utility. Average realized price on contract energy sales was $23.04 per MWh in 2009 compared to $28.89 per MWh in 2008. The expiration of the contract allowed more energy to be sold into the merchant market, but at lower average prices resulting in a $42 million decline in revenue. Megawatt hours sold to the merchant market increased by 41%, while prices fell by 50%. Increased use of the region’s tolled facility provided additional energy to the merchant market.

	o		Intercompany energy revenue — intercompany sales of $199 million by the Company’s Texas region to Reliant Energy were eliminated in consolidation.

•

Capacity revenue — decreased $246 million during the nine months ended September 30, 2009, compared to the same period in 2008:

	o		Texas — capacity revenue decreased by $222 million due to a lower proportion of baseload contracts which contained a capacity component.

	o		Northeast — capacity revenue decreased by $12 million due to lower capacity prices in the NYISO.

	o		South Central — capacity revenue increased by $30 million resulting primarily from a new capacity agreement.

	o		Intercompany capacity revenue — intercompany sales of $29 million by the Company’s Texas region to Reliant Energy were eliminated in consolidation.

	•		Contract amortization revenue — decreased by $325 million in the nine months ended September 30, 2009, as compared to the same period in 2008. The decrease includes a reduction of $166 million in revenue from the Texas Genco acquisition due to the lower volume of contracted energy and $160 million in amortization expense of net in-market C&I contracts related to the Reliant Energy acquisition in 2009.

	•		Other revenues — decreased by $82 million driven by $45 million in lower ancillary revenue, $46 million in lower emissions revenue, and a $26 million decrease in fuels trading. These decreases were offset by the recognition of a $31 million non-cash gain related to settlement of a pre-existing in-the-money contract with Reliant Energy.

Cost of Operations

Cost of operations, excluding risk management activities, increased $1.2 billion during the nine months ended September 30, 2009, compared to the same period in 2008.

•

Cost of sales — increased $1.1 billion during the nine months ended September 30, 2009, compared to the same period in 2008 due to:

	o		Retail — Reliant Energy incurred $1.8 billion of cost of energy during the five months ended September 30, 2009, which included $228 million of intercompany supply costs.

	o		Texas — cost of energy decreased $331 million due to lower natural gas, coal, purchased energy and ancillary services costs. Natural gas costs decreased $281 million, reflecting a 66% decline in average natural gas per MMBtu prices offset by a 6% increase in gas-fired generation. Coal costs decreased $17 million as the 2008 expense included a $15 million loss reserve related to a coal contract dispute and $6 million resulting from reduced generation. Ancillary service costs decreased by $41 million due to a decrease in purchased ancillary services costs incurred to meet contract obligations.

	o		Northeast — cost of energy decreased $254 million due to a $160 million reduction in natural gas and oil costs and a $108 million reduction in coal costs. Natural gas and oil costs decreased due to 28% lower generation and 60% lower average natural gas prices. Coal costs decreased due to 36% lower coal generation. These decreases were offset by a $15 million increase in costs related to RGGI which became effective in 2009.

	o		South Central — cost of energy decreased $71 million due to a $52 million decrease in purchased energy reflecting lower fuel costs associated with the region’s tolled facility and lower market energy prices, a $13 million decrease in natural gas cost, a $4 million decrease in coal costs and a $5 million decrease in transmission expense due to transmission line outages. The decrease in natural gas cost is attributable to a 32% decrease in gas generation and a 58% decrease in natural gas prices. The coal cost decreased due to a 7% decrease in generation offset by a 5% increase in price.

	o		West — cost of energy decreased $8 million due to a 43% decline in average natural gas per MMBtu prices offset by a 7% increase in natural gas consumption and a $2 million increase in fuel oil expense resulting from a write-down to market of fuel oil inventory no longer used in the production of energy.

	o		Intercompany cost of energy — intercompany purchases of $228 million by Reliant Energy from the Company’s Texas region were eliminated in consolidation.

•

Other cost of operations — increased $118 million during the nine months ended September 30, 2009, compared to the same period in 2008. Reliant Energy incurred $101 million which includes $62 million for customers service operations and $39 million for gross receipt tax on revenue. Further, operating and maintenance expenses increased by $6 million and property taxes increased by $11 million.

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 $556 million during the nine months ended September 30, 2009, compared to the same period in 2008. The breakdown of changes by region follows:


	Nine months ended September 30, 2009
	Reliant									South
(In millions)	Energy			Texas			Northeast			Central			West			Thermal			Elimination			Total

Net gains/(losses) on settled positions, or financial income in revenues	$	—		$	259		$	274		$	9		$	(6	)	$	4		$	(9	)	$	531

Mark-to-market results in revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges		—			(41	)		(90	)		—			1			(2	)		—			(132	)
Reversal of gain positions acquired as part of the Reliant Energy acquisition as of May 1, 2009		(1	)		—			—			—			—			—			—			(1	)
Reversal of previously recognized unrealized gains on settled positions related to trading activity		—			(51	)		(27	)		(47	)		—			—			—			(125	)
Net unrealized gains/(losses) on open positions related to economic hedges		—			59			89			(4	)		(1	)		2			14			159
Net unrealized gains/(losses) on open positions related to trading activity		—			(3	)		6			(4	)		—			—			—			(1	)

Subtotal mark-to-market results		(1	)		(36	)		(22	)		(55	)		—			—			14			(100	)

Total derivative gain/(loss) included in revenues	$	(1	)	$	223		$	252		$	(46	)	$	(6	)	$	4		$	5		$	431


	Nine months ended September 30, 2009
	Reliant									South
(In millions)	Energy			Texas			Northeast			Central			Elimination			Total

Net gains/(losses) on settled positions, or financial expense in cost of operations	$	(316	)	$	(17	)	$	(6	)	$	(7	)	$	22		$	(324	)

Mark-to-market results in cost of operations
Reversal of previously recognized unrealized losses on settled positions related to economic hedges		—			36			63			—			—			99
Reversal of loss positions acquired as part of the Reliant Energy acquisition as of May 1, 2009		449			—			—			—			—			449
Net unrealized gains/(losses) on open positions related to economic hedges		72			(84	)		(20	)		(26	)		(14	)		(72	)

Subtotal mark-to-market results		521			(48	)		43			(26	)		(14	)		476

Total derivative gain/(loss) included in cost of operations	$	205		$	(65	)	$	37		$	(33	)	$	8		$	152


	Nine months ended September 30, 2008
							South
(In millions)	Texas			Northeast			Central			Total

Net losses on settled positions, or financial income	$	(94	)	$	(67	)	$	(4	)	$	(165	)

Mark-to-market results
Reversal of previously recognized unrealized gains on settled positions related to economic hedges		(21	)		(11	)		—			(32	)
Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity		1			(7	)		(14	)		(20	)
Net unrealized gains on open positions related to economic hedges		95			58			—			153
Net unrealized gains on open positions related to trading activity		48			11			32			91

Subtotal mark-to-market results		123			51			18			192

Total derivative gain/(loss)	$	29		$	(16	)	$	14		$	27

Total derivative gain/(loss) included in revenues		29			(16	)		14			27
Total derivative gain included in cost of operations	$	—		$	—		$	—		$	—

NRG’s 2009 gain of $583 million during the nine months ended September 30, 2009, was comprised of $376 million of mark-to-market gains and $207 million in settled gains. Of the $376 million of mark-to-market gains there was a $476 million gain in expense and a $100 million loss in revenue. The $100 million loss in revenue consisted of a loss of $257 million from the reversal of mark-to-market gains recognized during 2008 offset by $158 million due to the increase in value of the forward purchases and sales of electricity and fuel. The $158 million gain consists of a $217 million gain recognized in earnings from previously deferred amounts in OCI as the Company discontinued cash flow hedge accounting in the first quarter for certain 2009 transactions in Texas and New York due to lower expected generation, offset by a $59 million decrease in value in forward sales of electricity and fuel due to lower forward power and gas prices. 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 was included in the Company’s cost of operations during the nine months ended September 30, 2009. The gain of $476 million in expense consists of $449 million of the Reliant Energy roll-off of loss positions, $99 million from the reversal of mark-to-market losses recognized during 2008 and a $72 million loss from the decrease in value of forward purchases of electricity and fuel.

Reliant Energy’s loss positions were acquired as of May 1, 2009, and valued using forward prices on that date. The $448 million roll-off amounts were offset by realized losses at the settled prices and are reflected in the cost of operations during the same period.

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 2009, NRG hedged a portion of the Company’s 2008 and 2009 generation. During the nine months ended September 30, 2009, the settled prices of electricity and natural gas decreased resulting in the recognition of realized gains while forward power and gas prices decreased resulting in the recognition of unrealized mark-to-market gains. During the nine months of 2008, decreasing forward prices of electricity and natural gas resulted in recognition of unrealized mark-to-market gains while the settled prices for power and gas increased resulting in the recognition of realized losses.

The following table represents the results of the Company’s financial and physical trading of energy commodities for the nine months ended September 30, 2009 and 2008. The realized financial trading results and unrealized financial and physical trading results are included in the risk management activities above, while the realized physical trading results are included in energy revenue.


	Nine months ended
	September 30,
(In millions)	2009			2008

Trading gains/(losses)
Realized	$	100		$	58
Unrealized		(126	)		72

Total trading gains/(losses)		(26	)		130

Depreciation and Amortization

NRG’s depreciation and amortization expense increased by $116 million for the nine months ended September 30, 2009, compared to the same period in 2008. Reliant Energy’s depreciation and amortization expense for the five month period was $85 million principally for amortization of customer relationships. The balance of the increase was due to depreciation on the baghouse projects in western New York and the Elbow Creek project which came online in late 2008, and the Cedar Bayou 4 plant which came online in the second quarter 2009.

Selling, General and Administrative Expenses

Selling, general and administrative expenses increased by $163 million for the nine months ended September 30, 2009, compared to the same period in 2008. The increase was due to:

	•		Reliant Energy’s selling, general and administrative expense — totaled $125 million, including $37 million of bad debt expense incurred during the five months ended September 30, 2009.

	•		Wage and benefits expense — increased $18 million.

	•		Consultant costs — increased $23 million consisting of non-recurring costs related to Exelon’s exchange offer and proxy contest efforts of $31 million offset by a decrease in other consulting costs of $8 million.

These increases were offset by:

•

Other expenses — decreased by $2 million. This decrease is attributable to a bad debt write-off in 2008.

Acquisition-Related Transaction and Integration Costs

NRG incurred Reliant Energy acquisition-related transaction costs of $29 million and integration costs of $12 million for the nine months ended September 30, 2009.

Equity in Earnings of Unconsolidated Affiliates

NRG’s equity earnings from unconsolidated affiliates decreased by $2 million for the nine months ended September 30, 2009, compared to the same period in 2008. During 2009, the Company’s share in Gladstone Power Station and MIBRAG decreased by $7 million and $11 million, respectively. These decreases were offset by the Company’s share of NRG Saguaro, LLC earnings increasing $9 million in 2009. In addition, there was a $7 million decrease in Sherbino I Wind Farm, LLC’s mark-to-market unrealized loss as compared to 2008 as a result of a natural gas swap executed to hedge to future power generation.

Gain on Sale of Equity Method Investments and Other Income/(Loss), Net

NRG’s gain on sale of equity method investments increased by $128 million for the nine months ended September 30, 2009, compared to the same period in 2008 and other (loss)/income, net decreased by $23 million for the nine months ended September 30, 2009, compared to the same period in 2008. The 2009 amounts include a $128 million gain on the sale of NRG’s 50% ownership interest in MIBRAG and a $24 million mark-to-market unrealized loss on a forward contract for foreign currency executed to hedge the sale proceeds from the MIBRAG sale. In addition, the 2009 interest income was lower compared to 2008 due to lower interest rates. Further in 2008, a $19 million impairment charge was incurred to restructure distressed investments in commercial paper.

Interest Expense

NRG’s interest expense increased by $33 million for the nine months ended September 30, 2009, compared to the same period in 2008. This increase was primarily due to a $28 million increase in fees incurred during the months of May through September of 2009 on the CSRA facility, a $19 million increase in interest expense as a result of the 2019 Senior Notes issued in June 2009, a $4 million increase related to ineffective portion of the interest rate cash flow hedges on the Company’s Term Loan Facility and a $8 million increase in the amortization of deferred financing costs. These increases were offset by a $25 million decrease in interest expense on the Company’s Term Loan Facility due to a decrease in the outstanding notional amount and lower interest rates related to the unhedged portion of Term Loan and fair value portion of Senior Notes.

Income Tax Expense

NRG’s income tax expense increased by $111 million for the nine months ended September 30, 2009, compared to the same period in 2008. The increase in income tax expense was primarily due to an increase in income coupled with the U.S. taxation of foreign earnings. The effective tax rate was 40.3% and 39.1% for the nine months ended September 30, 2009, and 2008, respectively.

Income from Discontinued Operations, Net of Income Tax Expense

For the nine months ended September 30, 2008, NRG recorded income from discontinued operations, net of income tax expense, of $172 million. NRG closed the sale of ITISA during the second quarter 2008.

Results of Operations for Reliant Energy

Reliant Energy

The following is a detailed discussion of the results of operations of NRG’s retail business segment since the date of acquisition.

Operating Strategy

Reliant Energy’s business is to earn a margin by selling electricity to end use customers, providing innovative and value-enhancing services to such customers, and acquiring supply for the estimated demand. As a retail energy provider, Reliant Energy arranges for the transmission and delivery of electricity to customers, bills customers, collects payment for electricity sold, develops innovative energy solutions, engages in energy efficiency initiatives and maintains call centers to provide customer service. Although NRG has begun the process of becoming the primary provider of Reliant Energy’s supply requirements, Reliant Energy presently purchases a substantial portion of its supply requirements from third parties such as generation companies and power marketers. Transmission and distribution services are purchased from entities regulated by the PUCT and subject to ERCOT protocols.

The energy usage of Reliant Energy’s retail customers varies by season, with generally higher usage during the summer period. As a result, Reliant Energy’s net working capital requirements generally increase during summer months along with the higher revenues, and then decline during off-peak months.

As of September 30, 2009, Reliant Energy had 1,161 employees, none of whom are covered by a bargaining agreement.

Customer Segments

The following is a description of Reliant Energy’s significant customer segments in Texas.

	•		Mass — Reliant Energy’s Mass customer base is made up of approximately 1.6 million residential and small business customers in the ERCOT market with more than half located in the Houston area. Reliant Energy also serves customers in other competitive markets in ERCOT including the Dallas, Fort Worth, and Corpus Christi areas.

	•		C&I — Reliant Energy markets electricity and energy services to approximately 0.1 million C&I customers in Texas. These customers include refineries, chemical plants, manufacturing facilities, hospitals, universities, commercial real estate, government agencies, restaurants, and other commercial facilities.

Market Framework

Reliant Energy operates within the same ERCOT market as the Company’s Texas region. For further discussion of the Texas market framework, see pages 25-26 of NRG Energy Inc.’s 2008 Annual Report on Form 10-K.

For further discussion of the Company’s Reliant Energy operations, see Item I, Note 4, Business Acquisition, to this Form 10-Q.

Selected Income Statement Data


	Three Months Ended			Period Ended
(In millions except otherwise noted)	September 30, 2009			September 30, 2009 ^(a)

Operating Revenues
Mass revenues	$	1,157		$	1,918
Commercial and industrial revenues		620			1,057
Supply management revenues		99			151
Risk management activities		(1	)		(1	)
Contract amortization		(85	)		(160	)

Total operating revenues		1,790			2,965
Operating Costs and Expenses
Cost of energy (including risk management activities)		1,203			1,817
Other operating expenses		136			226
Depreciation and amortization		42			85

Operating Income	$	409		$	837
Electricity sales volume — GWh (in thousands):
Mass		7,776			12,627
Commercial and Industrial ^(b)		8,199			13,780
Business Metrics
Weighted average retail customers count (in thousands, metered locations)
Mass		1,569			1,582
Commercial and Industrial ^(b)		68			69
Retail customers count (in thousands, metered locations)
Mass		1,552			1,552
Commercial and Industrial ^(b)		66			66
Cooling Degree Days, or CDDs ^(c)		1,760			2,731
CDD’s 30 year average		1,611			2,430
Heating Degree Days, or HDDs ^(c)		1			2
HDD’s 30 year average		2			7


(a)		For the period May 1, 2009, to September 30, 2009.
(b)		Includes customers of the Texas General Land Office for whom the Company provides services.
(c)		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. The CDDs/HDDs amounts are representative of the Coast and North Central Zones within the ERCOT market in which Reliant Energy serves its customer base.

Quarterly results

Operating Income

Operating income for the three months ended September 30, 2009, was $409 million, which consisted of the following:


	Three Months Ended
(In millions except otherwise noted)	September 30, 2009

Reliant Energy Operating Income:
Mass revenues	$	1,157
Commercial and industrial revenues		620
Supply management revenues		99

Total retail operating revenues ^(a)		1,876

Retail cost of sales ^(a)		1,433

Total retail gross margin		443
Unrealized gains on energy supply derivatives		217
Contract amortization, net		(73	)
Other operating expenses		(136	)
Depreciation and amortization		(42	)

Operating Income	$	409


(a)		Amounts exclude unrealized gains/(losses) on energy supply derivatives and contract amortization.

	•		Gross margin — Reliant Energy’s gross margin totaled $443 million for the quarter, which was driven by strong margins in the mass customer segment and expanding margins in the commercial and industrial segment. Volumes were higher due to greater customer usage as a result of warmer weather as compared to the 30 year CDD average, which was partially offset by a decrease in the number of customers during the three months ended September 30, 2009. Reliant Energy announced and enacted price reductions effective June 1 and July 1, 2009, that cumulatively, lowered prices up to 20% for certain Mass customers. These lower prices, relative to lower short term supply costs, delivered strong margins. Competition, price reductions, and supply costs based on forward market prices, will likely drive lower margins in the future.

			Relative to first half of 2009, competitive retail prices have decreased due to lower supply costs driven by a decline in natural gas prices. If supply costs continue to remain low, the Company expects competitive retail prices to continue to decline and place pressure on unit margins. Additionally, the Company’s customer counts have declined approximately 2% during the quarter.

	•		Risk management activities — Unrealized gains of $217 million on economic hedges relates to supply contracts that were recognized for the three months ended September 2009 including $239 million of gains representing a roll-off of loss positions acquired at May 1, 2009, valued at forward prices and $21 million of losses that represents mark-to-market changes in forward value of purchased electricity and gas. The $239 million gain from roll-off of loss positions is offset by realized losses at the settled prices and reflected in the cost of operations.

Operating Revenues

Total operating revenues for the three months ended September 30, 2009, were $1.8 billion and consisted of the following:

	•		Mass revenues — totaled $1,157 million for the quarter from retail electric sales to approximately 1.6 million end use customers in the Texas market. The current quarter revenue rates reflect the price reductions of up to 20% for certain Mass customer classes that were announced and enacted effective June 1 and July 1, 2009. Also, warmer weather, as compared to the 30 year CDD average, caused an increase in customer usage. The higher prices, along with higher usage, were accompanied by a 2% decrease in the number of customers during the quarter.

	•		Commercial and industrial revenue — As of May 1, 2009, Reliant Energy re-launched its C&I segment. C&I revenues for the three months ended September 30, 2009, totaled $620 million for the quarter on volume sales of approximately 8,199 GWh. Variable rate contracts tied to the market price of natural gas accounted for approximately 69% of the contracted volumes as of September 30, 2009.

	•		Contract amortization — reduced operating revenues by $85 million resulting from net in-market C&I contracts, which will continue to amortize over the term of the contracts acquired in the Reliant Energy acquisition.

	•		Supply management revenues — totaled $99 million for the quarter from the sale of excess supply into various markets in Texas.

Cost of Energy

Cost of energy for the three months ended September 30, 2009, was $1,203 million and consisted of the following:

	•		Supply costs — totaled $837 million for the quarter. The market cost of energy was relatively low during the quarter. This was driven by the lowest natural gas prices in the last three years for the same time period. Also, warmer weather for the period, as compared to the 30 year CDD average, caused an increase in purchased supply volumes at a relatively low cost.

	•		Risk management activities — Unrealized gains of $218 million on economic hedges relate to supply contracts that were recognized for the three months ended September 30, 2009, including $239 million of gains which represent a roll-off of loss positions acquired at May 1, 2009, valued at forward prices and $21 million of losses that represent mark-to-market changes in forward value of purchased electricity and gas. The $239 million gain from roll-off positions is offset by realized losses at the settled prices and reflected in cost of operations.

	•		Transmission and distribution charges — totaled $392 million for the quarter for the cost to transport the power from the generation sources to the end use customers.

	•		Financial settlements — totaled $202 million of losses for the quarter resulting from financial settlement of energy related derivatives.

	•		Contract amortization — reduced the cost of energy by $11 million, resulting from the net out-of-market supply contracts established at the acquisition date. These contracts will be amortized over the life of the contracts.

Other Operating Expenses

Other operating expenses for the three months ended September 30, 2009, were $136 million, or 8% of the region’s total operating revenues. Other operating expenses consisted of the following:

	•		Operations and maintenance expenses — totaled $37 million for the quarter, primarily consisted of the labor and external costs associated with customer activities, including the call center, billing, remittance processing, and credit and collections, as well as the information technology costs associated with those activities.

	•		Selling, general and administrative expenses — totaled $48 million for the quarter, primarily consisted of the costs of labor and external costs associated with advertising and other marketing activities, as well as human resources, community activities, legal, procurement, regulatory, accounting, internal audit, and management, as well as facilities leases and other office expenses.

	•		Gross receipts tax — totaled $24 million for the quarter or 1.3% of Mass and C&I revenues.

	•		Bad debt expense — totaled $28 million for the quarter or 1.6% of Mass and C&I revenues which was driven by higher summer bills due to warmer weather and economic factors including unemployment in Dallas and Houston, which approximated national averages.

Year to date results

Operating Income

Operating income for the period ended September 30, 2009, was $837 million, which consisted of the following:


	Period Ended
(In millions except otherwise noted)	September 30, 2009

Reliant Energy Operating Income:
Mass revenues	$	1,918
Commercial and industrial revenues		1,057
Supply management revenues		151

Total retail operating revenues ^(a)		3,126

Retail cost of sales ^(a)		2,363

Total retail gross margin		763
Unrealized gains on energy supply derivatives		520
Contract amortization, net		(135	)
Other operating expenses		(226	)
Depreciation and amortization		(85	)

Operating Income	$	837


(a)		Amounts exclude unrealized gains/(losses) on energy supply derivatives and contract amortization.

	•		Gross margin — Reliant Energy’s gross margin totaled $763 million, which was driven by strong margins in the mass customer segment and expanding margins in the commercial and industrial segment. Volumes were higher due to greater customer usage as a result of warmer weather as compared to the 30 year CDD average, although partially offset by a decrease in number of customers during the five months ended September 30, 2009. The Company acquired Reliant Energy customers on prices more consistent with 2008 costs of natural gas. Reliant Energy announced and enacted price reductions effective June 1 and July 1, 2009, that cumulatively lowered prices up to 20% for certain Mass customers. These lower prices, relative to lower short term supply costs, delivered strong margins. Competition, price reductions, and supply costs based on forward market prices, will likely drive lower margins in the future.

			With the decline in natural gas prices, and the corresponding decline in the cost of energy supply, competitive retail prices have decreased relative to 2008. If supply costs continue to remain low, the Company expects competitive retail prices to continue to decline and place pressure on unit margins. Additionally, the Company’s customer counts have declined approximately 4% since May 1, 2009.

	•		Risk management activities — Unrealized gains of $520 million on economic hedges relates to supply contracts that were recognized for the period ended September 2009 including $448 million of gains representing a roll-off of loss positions acquired at May 1, 2009, valued at forward prices and $72 million of gains that represents mark-to-market changes in forward value of purchased electricity and gas. The $448 million gain from roll-off of loss positions is offset by realized losses at the settled prices and reflected in the cost of operations. In August 2009, Reliant Energy entered into two contracts to mitigate a portion of Reliant Energy’s exposure to lost revenue as a result of a hurricane during the 2009 season. The contracts premiums of $5.7 million provided coverage for a $50 million loss.

Operating Revenues

Total operating revenues for the period ended September 30, 2009, were $3.0 billion and consisted of the following:

	•		Mass revenues — totaled $1,918 million from retail electric sales to approximately 1.6 million end use customers in the Texas market. Revenue rates for acquired Reliant Energy customers were not consistent with current costs of natural gas. These acquired revenue rates were reduced by Reliant Energy’s announced and enacted price reductions effective June 1 and July 1, 2009 of up to 20% for certain Mass customers classes. Also, warmer weather, as compared to the 30 year CDD average, caused an increase in customer usage. The higher prices, along with higher usage, were accompanied by a 4% decrease in the number of customers since May 1, 2009.

	•		Commercial and industrial revenue — As of May 1, 2009, Reliant Energy re-launched its C&I segment. C&I revenues for the period ended September 30, 2009, totaled $1,057 million on volume sales of roughly 13,780 GWh. Variable rate contracts tied to the market price of natural gas accounted for approximately 71% of the contracted volumes as of September 30, 2009.

	•		Contract amortization — reduced operating revenues by $160 million resulting from net in-market C&I contracts, which will continue to amortize over the term of the contracts acquired in the Reliant Energy acquisition.

	•		Supply management revenues — totaled $151 million from the sale of excess supply into various markets in Texas.

Cost of Energy

Cost of energy for the period ended September 30, 2009, was $1,817 million and consisted of the following:

	•		Supply costs — totaled $1,387 million. The market cost of energy is significantly down for the period. Natural gas prices have declined 69% since the same period last year. Also, warmer weather for the period, as compared to the 30 year CDD average, caused an increase in purchased supply volumes at a relatively low cost.

	•		Risk management activities — Unrealized gains of $521 million on economic hedges relate to supply contracts that were recognized for the period ended September 30, 2009, including $449 million of gains which represent a roll-off of loss positions acquired at May 1, 2009, valued at forward prices and $72 million of gains that represent mark-to-market changes in forward value of purchased electricity and gas. The $449 million gain from roll-off of loss positions is offset by realized losses at the settled prices and reflected in cost of operations.

	•		Transmission and distribution charges — totaled $659 million for the cost to transport the power from the generation sources to the end use customers.

	•		Financial settlements — totaled $316 million resulting from financial settlement of energy related derivatives.

	•		Contract amortization — reduced the cost of energy by $24 million, resulting from the net out-of-market supply contracts established at the acquisition date. These contracts will be amortized over the life of the contracts.

Other Operating Expenses

Other operating expenses for the period ended September 30, 2009, were $226 million, or 8% of the region’s total operating revenues. Other operating expenses consisted of the following:

	•		Operations and maintenance expenses — totaled $62 million, primarily consisted of the labor and external costs associated with customer activities, including the call center, billing, remittance processing, and credit and collections, as well as the information technology costs associated with those activities.

	•		Selling, general and administrative expenses — totaled $88 million, primarily consisted of the costs of labor and external costs associated with advertising and other marketing activities, as well as human resources, community activities, legal, procurement, regulatory, accounting, internal audit, and management, as well as facilities leases and other office expenses.

	•		Gross receipts tax — totaled $39 million or 1.3% of Mass and C&I revenues.

	•		Bad debt expense — totaled $37 million or 1.2% of Mass and C&I revenues which was driven by higher summer bills due to warmer weather and economic factors including unemployment in Dallas and Houston which approximated national averages.

Results of Operations for Wholesale Power Generation Regions

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


	Three months ended September 30,							Nine months ended September 30,
(In millions except otherwise noted)	2009		2008		Change %			2009		2008		Change %

Operating Revenues
Energy revenue	$	672	$	873		(23	)%	$	1,866	$	2,344		(20	)%
Capacity revenue		50		129		(61	)		144		366		(61	)
Risk management activities		14		552		(97	)		223		29		N/A
Contract amortization		17		69		(75	)		49		215		(77	)
Other revenues		7		14		(50	)		22		83		(73	)

Total operating revenues		760		1,637		(54	)		2,304		3,037		(24	)
Operating Costs and Expenses
Cost of energy (including risk management activities)		296		366		(19	)		770		1,037		(26	)
Other operating expenses		164		154		6			486		468		4
Depreciation and amortization		119		108		10			353		334		6

Operating Income	$	181	$	1,009		(82	)	$	695	$	1,198		(42	)
MWh sold (in thousands)		13,979		13,111		7			36,485		36,817		(1	)
MWh generated (in thousands)		12,534		12,891		(3	)		34,527		36,147		(4	)
Business Metrics
Average on-peak market power prices ($/MWh)		33.68		102.82		(67	)		37.51		112.80		(67	)
Cooling Degree Days, or CDDs ^(a)		1,601		1,417		13			2,709		2,509		8
CDD’s 30 year average		1,485		1,485		—			2,433		2,434		—
Heating Degree Days, or HDDs ^(a)		5		6		(17	)%		1,008		1,163		(13	)
HDD’s 30 year average		5		5		—			1,210		1,221		(1	)%


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

Quarterly Results

Operating Income

Operating income decreased by $828 million for the three months ended September 30, 2009, compared to the same period in 2008, due to:

	•		Operating revenues — decreased by $877 million due to a reduced impact from risk management activities, in addition to lower energy revenues due to lower average energy prices and lower sales volume.

	•		Cost of energy — decreased by $70 million resulting from lower natural gas costs.

Operating Revenues

Total operating revenues decreased by $877 million during the three months ended September 30, 2009, compared to the same period in 2008, due to:

	•		Risk management activities — decreased by $538 million due to the difference between gains of $14 million for the three months ending September 30, 2009, compared to gains of $552 million during the same period in 2008. The $14 million gain included $102 million of unrealized mark-to-market losses and $116 million in gains on settled transactions, or financial income, compared to $596 million in unrealized mark-to-market gains and $44 million in financial losses during the same period in 2008. Please refer to the consolidated Management’s Discussion and Analysis for a more complete description of movements in risk management activities.

	•		Energy revenues — decreased $201 million due to:

	o		Energy prices — decreased by $177 million as the prices continue to remain lower in the third quarter 2009 compared to the same period 2008. The average realized energy price decreased by 21%, driven by a 53% decrease in merchant prices offset by a 21% increase in contract prices.

	o		Generation — decreased by 3% resulting in a $24 million decrease in sales volume. This decrease was driven by an 11% decrease in coal plant generation and an 8% decrease in nuclear plant generation. Coal plant generation was adversely affected by lower energy prices driven by a 64% decrease in average natural gas prices. This was offset by a 47% increase in gas plant generation due to very warm temperatures in the third quarter 2009 compared to the same period 2008, as well as generation from the recently constructed Cedar Bayou 4 gas plant and Elbow Creek wind farm which began commercial operations in June 2009 and December of 2008, respectively.

	•		Capacity revenue — decreased by $79 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 $52 million due to the reduced volume of contracted energy in 2009 as compared to 2008.

	•		Other revenue — decreased by $7 million primarily due to lower ancillary services revenue of $16 million. This decrease was offset by $6 million higher physical sales of natural gas and coal and $1 million higher emissions credit revenue.

Cost of Energy

Cost of energy decreased by $70 million during the three months ended September 30, 2009, compared to the same period in 2008, due to:

	•		Natural gas costs — decreased by $84 million due to a 64% decline in average natural gas prices offset by a 47% increase in gas-fired generation.

	•		Ancillary services costs — decreased by $19 million due to a decrease in purchased ancillary services costs incurred to meet obligations.

	•		Coal and nuclear fuel costs — decreased by $7 million due to lower generation, offset by an $8 million increase in nuclear fuel due to the reversal of amortization of nuclear fuel inventory established under Texas Genco accounting.

These decreases were offset by:

	•		Purchased energy — increased $13 million due to baseload units either unavailable or uneconomic to provide power for contract commitments.

	•		Cost contract amortization – increased $10 million driven primarily by the reduction in amortization credit for out-of-the money coal contracts assumed in the acquisition of Texas Genco as coal is delivered under that contract.

•

Fuel risk management activities — losses of $11 million were recorded for the three months ending September 30, 2009. In the first quarter 2009, all NPNS coal contracts were discontinued and reclassified into mark-to-market accounting. The $11 million loss included $7 million of unrealized mark-to-market losses, largely associated with forward coal positions and $4 million in losses on settled transactions, or financial cost of energy. Please refer to the consolidated Management’s Discussion and Analysis for a more complete description of movements in risk management activities.

Other Operating Expenses

Other operating expenses increased by $10 million during the three months ended September 30, 2009, compared to the same period in 2008, driven by an increase of $9 million in general and administrative expenses due to higher corporate allocations as a result of the change in method in allocating corporate costs as described in Note 12, Segment Reporting, in combination with a $3 million increase in operations and maintenance expense as a result of maintenance outages at the region’s baseload plants.

Depreciation and Amortization

Depreciation and amortization expense increased by $11 million for the three months ended September 30, 2009, compared to the same period in 2008. This increase is the result of Cedar Bayou 4 and Elbow Creek reaching commercial operations in June 2009 and December 2008, respectively.

Year to date results

Operating Income

Operating income decreased by $503 million for the nine months ended September 30, 2009, compared to the same period in 2008, primarily due to:

	•		Operating revenues — decreased by $733 million due to unfavorable energy and capacity revenues offset by favorable impact of risk management activities.

	•		Cost of energy — decreased by $267 million reflecting lower natural gas costs and a decrease in coal generation.

Operating Revenues

Total operating revenues decreased by $733 million during the nine months ended September 30, 2009, compared to the same period in 2008, due to:

•

Energy revenues — decreased $478 million due to:

	o		Energy prices — decreased by $373 million as the average realized merchant price was lower in 2009 due to the combination of lower gas prices and unusually high pricing events that occurred in 2008 but did not repeat in 2009. Higher MWh sold under merchant market was offset by lower merchant prices. The average realized energy price decreased by 17%, driven by a 52% decrease in merchant prices offset by a 23% increase in contract prices.

	o		Generation — decreased by 5% resulting in a $105 million decrease in sales volume. This decrease was driven by a 9% decrease in coal plant generation. This was offset by a 6% increase in gas plant generation, and generation from the recently constructed Cedar Bayou 4 gas plant and Elbow Creek wind farm which began commercial operation in June 2009 and December 2008, respectively. Coal plant generation was adversely affected by lower energy prices driven by a 66% decrease in average natural gas prices in combination with increased wind generation in the region.

	•		Capacity revenue — decreased by $222 million due to a lower proportion of baseload contracts which contain a capacity component.

	•		Risk management activities — increased by $194 million due to the difference between gains of $223 million recorded for the nine months ending September 30, 2009, compared to gains of $29 million during the same period in 2008. The $223 million gain included $36 million of unrealized mark-to-market losses and $259 million in gains on settled transactions, or financial income, compared to $123 million in unrealized mark-to-market gains and $94 million in financial losses during the same period in 2008. Please refer to the consolidated Management’s Discussion and Analysis for a more complete description of movements in risk management activities.

	•		Contract amortization revenue — resulting from the Texas Genco acquisition decreased by $166 million due to the reduced volume of contracted energy in 2009 as compared to 2008.

	•		Other revenue — decreased by $61 million primarily due to lower ancillary services revenue of $41 million provided to the market, lower emissions credit revenue of $13 million and reduced physical sales of natural gas and coal of $7 million.

Cost of Energy

Cost of energy decreased by $267 million during the nine months ended September 30, 2009, compared to the same period in 2008, due to:

	•		Natural gas costs — decreased by $281 million due to a 66% decline in average natural gas prices offset by a 6% increase in gas-fired generation.

	•		Ancillary service costs — decreased by $41 million due to a decrease in purchased ancillary services costs incurred to meet contract obligations.

	•		Coal costs — decreased by $17 million as the first three months of 2008 included a $15 million loss reserve related to a coal contract dispute in addition to a decrease of $6 million due to lower generation. These decreases were offset by higher transportation costs of $9 million.

These decreases were offset by:

•

Fuel risk management activities — losses of $65 million were recorded for the nine months ending September 30, 2009. In the first quarter 2009, all NPNS coal contracts were discontinued and reclassified into mark-to-market accounting. The $65 million loss included $48 million of unrealized mark-to-market losses, largely associated with forward coal positions and $17 million in losses on settled transactions, or financial cost of energy. Please refer to the consolidated Management’s Discussion and Analysis for a more complete description of movements in risk management activities.

Other Operating Expenses

Other operating expenses increased by $18 million during the nine months ended September 30, 2009, compared to the same period in 2008, driven by an increase of $14 million in general and administrative expense due to higher corporate allocations as a result of the change in method in allocating corporate costs as described in Note 12, Segment Reporting, to this Form 10-Q. In addition there was an increase of $4 million for development expense as prior year results included a one time credit due to the reimbursement by the Company’s nuclear development partner of previously expensed development costs on STP units 3 and 4 of $8 million.

Depreciation and Amortization

Depreciation and amortization expense increased by $19 million for the nine months ended September 30, 2009, compared to the same period in 2008. This increase was the result of Cedar Bayou 4 and Elbow Creek reaching commercial operations in June 2009 and December 2008, respectively.

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


	Three months ended September 30,							Nine months ended September 30,
(In millions except otherwise noted)	2009		2008		Change %			2009		2008			Change %

Operating Revenues
Energy revenue	$	123	$	324		(62	)%	$	383	$	873			(56	)%
Capacity revenue		120		117		3			316		328			(4	)
Risk management activities		19		168		(89	)		252		(16	)		N/A
Other revenues		8		13		(38	)		20		62			(68	)

Total operating revenues		270		622		(57	)		971		1,247			(22	)
Operating Costs and Expenses
Cost of energy (including risk management activities)		90		198		(55	)		265		557			(52	)
Other operating expenses		88		89		(1	)		276		273			1
Depreciation and amortization		29		26		12			88		77			14

Operating Income	$	63	$	309		(80	)	$	342	$	340			1
MWh sold (in thousands)		2,508		3,588		(30	)		6,779		10,424			(35	)
MWh generated (in thousands)		2,508		3,588		(30	)		6,779		10,424			(35	)
Business Metrics
Average on-peak market power prices ($/MWh) ^(b)		40.42		108.44		(63	)		46.13		100.66			(54	)
Cooling Degree Days, or CDDs ^(a)		419		446		(6	)		496		611			(19	)
CDD’s 30 year average		429		430		—			534		534			—
Heating Degree Days, or HDDs ^(a)		129		135		(4	)		4,126		3,866			7
HDD’s 30 year average		158		159		(1	)%		4,093		4,126			(1	)%


(a)		National Oceanic and Atmospheric Administration-Climate Prediction Center - A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period.
(b)		MWh sold are shown net of MWh purchased to satisfy certain load contracts in the region.

Quarterly Results

Operating Income

Operating income decreased by $246 million for the three months ended September 30, 2009, compared to the same period in 2008 due to:

	•		Operating revenues — decreased by $352 million due to unfavorable energy revenues and an unfavorable impact from risk management activities.

	•		Cost of energy — decreased by $108 million due to lower generation and fuel costs.

Operating Revenues

Operating revenues decreased by $352 million for the three months ended September 30, 2009, compared to the same period in 2008, due to:

•

Energy revenues — decreased by $201 million due to:

	o		Energy prices — decreased by $120 million reflecting an average 52% decline in merchant energy prices. This decrease was partially offset by higher net contract revenues of $18 million driven by lower net costs incurred in meeting obligations under load serving contracts in the PJM market.

	o		Generation — decreased by $99 million due to a 30% decrease in generation in 2009 compared to 2008, with a 34% decrease in coal generation and a 9% decrease in oil and gas generation. Coal generation in western New York declined 33%, or 568,247 MWhs, due to weak power prices that made the plants uneconomic to dispatch. Coal generation at the Indian River plant declined 35%, or 305,203 MWhs, due to a combination of weakened demand for power, low gas prices and higher cost of production from compliance with RGGI resulting in increased hours where the units were uneconomic to dispatch. The Somerset plant experienced similar weakened demand and low gas prices, with generation down 82%, or 111,819 MWh.

These decreases were offset by:

•

Risk management activities — gains of $19 million were recorded for the three months ending September 30, 2009, compared to gains of $168 million during the same period in 2008. The $19 million gain included $99 million of unrealized mark-to-market losses and $118 million in gains on settled transactions, or financial income, compared to $211 million in unrealized mark-to-market gains and $43 million in financial losses during the same period in 2008. Please refer to the consolidated Management’s Discussion and Analysis for a more complete description of movements in risk management activities.

Cost of Energy

•

Cost of energy decreased by $108 million for the three months ended September 30, 2009, compared to the same period in 2008, due to:

	o		Natural gas and oil costs — decreased by $53 million, or 57%, due to 9% lower generation and 67% lower average natural gas prices.

	o		Coal costs — decreased by $39 million, or 38%, due to lower coal generation of 34% accounting for $33 million and lower prices accounting for $6 million.

	o		Fuel risk management activities — gains of $22 million were recorded for the three months ending September 30, 2009. In the first quarter 2009, all NPNS coal contracts were discontinued and reclassified into mark-to-market accounting. The $22 million gain included $23 million of mark-to-market gains, largely associated with forward coal positions and $1 million in losses on settled transactions, or financial cost of energy. Please refer to the consolidated Management’s Discussion and Analysis for a more complete description of movements in risk management activities.

These decreases were offset by:

•

Carbon emission expense — increased by $6 million due to the January 1, 2009, implementation of RGGI and the recognition of carbon compliance cost under this program.

Year-to-Date Results

Operating Income

Operating income increased by $2 million for the nine months ended September 30, 2009, compared to the same period in 2008 due to:

•

Cost of energy — decreased by $292 million due to lower generation and fuel costs.

This decrease was offset by:

	•		Operating revenues — decreased by $276 million due to unfavorable energy revenues, other revenues and capacity revenues partially offset by a favorable impact from risk management activities.

	•		Depreciation and amortization — increased by $11 million primarily due to depreciation from the 2009 baghouse projects at our Western New York coal plants and additional depreciation recognized in 2009 compared to 2008 from the June 2008 Cos Cob repowering project.

Operating Revenues

Operating revenues decreased by $276 million for the nine months ended September 30, 2009, compared to the same period in 2008, due to:

•

Energy revenues — decreased by $490 million due to:

	o		Energy prices — decreased by $231 million reflecting an average 40% decline in merchant energy prices. This decrease was partially offset by higher net contract revenues of $53 million driven by lower net costs incurred in meeting obligations under load serving contracts in the PJM market.

	o		Generation — decreased by $312 million due to a 35% decrease in generation in 2009 compared to 2008, driven by a 36% decrease in coal generation and a 28% decrease in oil and gas generation. Coal generation in western New York declined 31% or 1,480,454 MWhs due to weak power prices that made the plants uneconomic to dispatch. Coal generation at the Indian River plant declined 44% or 1,257,936 MWhs due to a combination of weakened demand for power, low gas prices and higher cost of production from the introduction of RGGI resulting in increased hours where the units were uneconomic to dispatch. The Somerset plant experienced similar weakened demand and low gas prices, with generation down 79% or 408,435 MWh. The decline in oil and gas generation is attributable to fewer reliability run hours at the Norwalk plant and a higher maintenance work at the Arthur Kill plant in 2009.

	•		Other revenues — decreased by $42 million due to $22 million from decreased activity in the trading of emission allowances and $17 million lower allocations of net physical gas sales.

	•		Capacity revenues — decreased by $12 million due to lower capacity cash flow revenue in New York in 2009.

These decreases were offset by:

•

Risk management activities — gains of $252 million were recorded for the nine months ending September 30, 2009, compared to losses of $16 million during the same period in 2008. The $252 million gain included $22 million of unrealized mark-to-market losses and $274 million in gains on settled transactions, or financial income, compared to $51 million in unrealized mark-to-market gains and $67 million in financial losses during the same period in 2008. Please refer to the consolidated Management’s Discussion and Analysis for a more complete description of movements in risk management activities.

Cost of Energy

•

Cost of energy decreased by $292 million for the nine months ended September 30, 2009, compared to the same period in 2008, due to:

	o		Natural gas and oil costs — decreased by $160 million, or 61%, due to 28% lower generation and 60% lower average natural gas prices.

	o		Coal costs — decreased by $108 million, or 38%, due to lower coal generation of 36% accounting for $106 million and lower prices accounting for $2 million.

	o		Fuel risk management activities — gains of $37 million were recorded for the nine months ended September 30, 2009. In the first quarter 2009, all NPNS coal contracts were discontinued and reclassified to mark-to-market accounting. The $37 million gain included $43 million of unrealized mark-to-market gains, largely associated with forward coal positions and $6 million in losses on settled transactions, or financial cost of energy. Please refer to the consolidated Management’s Discussion and Analysis for a more complete description of movements in risk management activities.

These decreases were offset by:

Carbon emission expense — increased by $15 million due to the January 1, 2009, implementation of RGGI and the recognition of carbon compliance cost under this program.

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


	Three months ended September 30,									Nine months ended September 30,
(In millions except otherwise noted)	2009			2008			Change%			2009			2008		Change%

Operating Revenues
Energy revenue	$	90		$	145			(38	)%	$	267		$	375		(29	)%
Capacity revenue		71			59			20			204			174		17
Risk management activities		(27	)		24			N/A			(46	)		14		N/A
Contract amortization		8			7			14			19			18		6
Other revenues		1			(1	)		N/A			—			4		N/A

Total operating revenues		143			234			(39	)		444			585		(24	)
Operating Costs and Expenses
Cost of energy (including risk management activities)		122			156			(22	)		324			360		(10	)
Other operating expenses		27			25			8			76			80		(5	)
Depreciation and amortization		16			16			—			50			50		—

Operating (Loss)/Income	$	(22	)	$	37			(159	)	$	(6	)	$	95		(106	)
MWh sold (in thousands)		3,243			3,383			(4	)		9,204			9,448		(3	)
MWh generated (in thousands)		2,727			2,828			(4	)		7,819			8,469		(8	)
Business Metrics
Average on-peak market power prices ($/MWh)		29.50			84.88			(65	)		33.00			79.14		(58	)
Cooling Degree Days, or CDDs ^(a)		952			1,027			(7	)		1,540			1,577		(2	)
CDD’s 30 year average		997			997			—			1,486			1,487		—
Heating Degree Days, or HDDs ^(a)		14			16			(13	)%		2,108			2,239		(6	)
HDD’ 30 year average		33			33			—			2,227			2,246		(1	)%


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

Quarterly Results

Operating income decreased by $59 million for the three months ended September 30, 2009, compared to the same period in 2008, primarily due to:

	•		Operating revenues — decreased by $91 million due to decreases in energy revenue and risk management activities offset by increased capacity revenue.

	•		Cost of energy — decreased by $34 million due to lower purchased energy, fuel and transmission costs, offset by higher fuel risk management activities.

	•		Other operating expenses — increased by $2 million due to higher maintenance expense offset by lower general and administrative costs.

Operating Revenues

Operating revenues decreased by $91 million for the three months ended September 30, 2009, compared to the same period in 2008, due to:

	•		Energy revenues — decreased by $55 million due to a $24 million decline in contract revenue coupled with a decrease of $31 million in merchant energy revenues. Total MWh sales to the region’s contract customers were down 7% while the average realized price on contract energy sales was $22.83 per MWh in 2009 compared to $29.19 per MWh in 2008. The decline in contract energy price was driven by a $7 million decrease in fuel cost pass through from the cooperatives. Also contributing to the decline in contract revenue was $17 million due to the expiration of a contract with a regional utility. The expiration of the contract allowed more energy to be sold into the merchant market, but at lower average prices resulting in a $31 million decline in revenue. Megawatt hours sold to the merchant market increased by 18% as increased use of the region’s tolled facility provided additional energy to the merchant market while prices fell by 61% to $54.52/MWh.

	•		Risk management activities — losses of $27 million were recorded for the three months ending September 30, 2009, compared to gains of $24 million during the same period in 2008. The $27 million loss included $25 million of unrealized mark-to-market losses and $2 million in losses on settled transactions, or financial income, compared to $28 million in unrealized mark-to-market gains and $4 million in financial losses during the same period in 2008. Please refer to the consolidated Management’s Discussion and Analysis for a more complete description of movements in risk management activities.

	•		Capacity revenues — capacity revenue increased by $12 million due to an $11 million increase from a new capacity agreement and a $1 million increase in capacity revenue from the region’s Rockford plants which dispatch into the PJM market.

Cost of Energy

Cost of energy decreased by $34 million for the three months ended September 30, 2009, compared to the same period in 2008, due to:

	•		Purchased energy — Total purchased energy and capacity decreased by $35 million. Purchased energy costs decreased by $35 million reflecting a 2% decrease in MWhs purchased and a 65% decrease in price reflecting lower fuel costs associated with energy from the region’s tolled facility and lower costs of market purchases.

	•		Natural gas expense — decreased by $14 million reflecting an 88% decrease in gas generation and a 61% decrease in gas prices. The region’s gas facilities ran extensively to support transmission system stability following hurricane Gustav in September 2008.

	•		Coal expense — decreased $2 million as cost per ton was $31.94 compared to $32.46 for the same period last year reflecting lower fuel transportation surcharges partially offset by increased transportation contract rates.

These decreases were offset by:

•

Fuel risk management activities — losses of $17 million were recorded for the three months ending September 30, 2009. In the first quarter 2009, all NPNS coal contracts were discontinued and reclassified into mark-to-market accounting. The $17 million loss included $16 million of unrealized mark-to-market losses, largely associated with forward coal positions and $1 million in losses on settled transactions, or financial cost of energy. Please refer to the consolidated Management’s Discussion and Analysis for a more complete description of movements in risk management activities.

Other Operating Expenses

Other operating expense increased by $2 million for the three months ended September 30, 2009, compared to the same period in 2008, due to:

	•		Operations and maintenance expense — increased by $4 million because of work done on river docking facility used for barge unloading and expenditures in preparation for fall outages.

	•		General and administrative expense — declined by $2 million due to lower corporate allocations as such costs are spread over a wider base following the Reliant Energy acquisition.

Year-to-Date Results

Operating income decreased by $101 million for the nine months ended September 30, 2009, compared to the same period in 2008, primarily due to:

	•		Operating revenues — decreased by $141 million due to decreases in energy revenue, risk management activities, and other revenue. These decreases were offset by an increase in capacity revenue.

	•		Cost of energy — decreased by $36 million due to lower purchased energy, fuel and transmission costs, offset by higher fuel risk management activities.

	•		Other operating expenses — decreased by $4 million because of lower general and administrative costs.

Operating Revenues

Operating revenues decreased by $141 million for the nine months ended September 30, 2009, compared to the same period in 2008, due to:

	•		Energy revenues — decreased by $108 million due to a $66 million decline in contract revenue coupled with a $42 million decrease in merchant energy revenues. Contract customer sales volumes were down 10% while the average realized price on contract energy sales was $23.04 per MWh in 2009 compared to $28.89 per MWh in 2008. The decline in contract energy price was driven by a $12 million decrease in fuel cost pass through to the cooperatives. Also contributing to the decline in contract revenue was $48 million due to the expiration of a contract with a regional utility. The expiration of the contract allowed more energy to be sold into the merchant market, but at lower average prices resulting in a $42 million decline in revenue. Megawatt hours sold to the merchant market increased by 41%, while prices fell by 50% to $52.10/MWh. Increased use of the region’s tolled facility provided additional energy to the merchant market.

	•		Risk management activities — losses of $46 million were recorded for the nine months ending September 30, 2009, compared to gains of $14 million during the same period in 2008. The $46 million loss included $55 million of unrealized mark-to-market losses offset by $9 million in gains on settled transactions, or financial income, compared to $18 million in unrealized mark-to-market gains offset by $4 million in financial losses during the same period in 2008. Please refer to the consolidated Management’s Discussion and Analysis for a more complete description of movements in risk management activities

	•		Other revenue — declined by $4 million due to $1 million in lower physical coal and natural gas sales and $3 million reduction in emission sales.

These decreases were offset by:

•

Capacity revenues — increased by $30 million due to a $30 million increase from new capacity agreements with regional utilities and a $5 million increase in capacity revenue from the region’s Rockford plants which dispatch into the PJM market, offset by lower contract capacity revenue of $5 million.

Cost of Energy

Cost of energy decreased by $36 million for the nine months ended September 30, 2009, compared to the same period in 2008, due to:

	•		Purchased energy — decreased by $52 million while purchased capacity increased by $3 million. The lower purchased energy reflects lower fuel costs associated with the region’s tolled facility and lower market energy prices. The energy declines were offset by higher capacity payments of $3 million on tolled facilities.

	•		Natural gas expense – decreased by $13 million reflecting a 32% decrease in gas generation and a 58% decrease in gas prices. The region’s gas facilities ran extensively to support transmission system stability following hurricane Gustav in September 2008.

	•		Transmission expense — decreased by $5 million due to certain transmission line outages between electrical power regions which limited merchant energy volumes that would attract transmission costs as well as lower network interchange transmission costs associated with reduced contract customer energy volumes.

	•		Coal expense — decreased $4 million as coal generation was down 7%, offset by a 5% increase in cost per ton.

These decreases were offset by:

•

Fuel risk management activities — losses of $33 million were recorded for the nine months ending September 30, 2009. In the first quarter 2009, all NPNS coal contracts were discontinued and reclassified into mark-to-market accounting. The $33 million loss included $26 million of unrealized mark-to-market losses largely associated with forward coal positions and $7 million in losses on settled transactions, or financial cost of energy. Please refer to the consolidated Management’s Discussion and Analysis for a more complete description of movements in risk management activities.

Other Operating Expenses

Other operating expense decreased by $4 million for the nine months ended September 30, 2009, compared to the same period in 2008, due to:

•

General and administrative expense — declined by $4 million due to lower corporate allocations as such costs are spread over a wider base following the Reliant Energy acquisition.

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


	Three months ended September 30,								Nine months ended September 30,
(In millions except otherwise noted)	2009			2008		Change%			2009			2008		Change%

Operating Revenues
Energy revenue	$	15		$	12		25	%	$	22		$	25		(12	)%
Capacity revenue		33			28		18			93			97		(4	)
Risk management activities		(9	)		—		N/A			(6	)		—		N/A
Other revenues		1			—		N/A			1			5		(80	)

Total operating revenues		40			40		—			110			127		(13	)
Operating Costs and Expenses
Cost of energy (including risk management activities)		10			11		(9	)		17			25		(32	)
Other operating expenses		15			14		7			61			52		17
Depreciation and amortization		2			2		—			6			6		—

Operating Income	$	13		$	13		—		$	26		$	44		(41	)
MWh sold (in thousands)		569			534		7			921			1,002		(8	)
MWh generated (in thousands)		569			534		7			921			1,002		(8	)
Business Metrics
Average on-peak market power prices ($/MWh)		38.78			96.72		(60	)		37.46			91.52		(59	)
Cooling Degree Days, or CDDs ^(a)		741			687		8			885			893		(1	)
CDD’s 30 year average		506			506		—			663			663		—
Heating Degree Days, or HDDs ^(a)		43			61		(30	)%		1,923			2,157		(11	)
HDD’s 30 year average		108			108		—			2,083			2,098		(1	)%


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

Quarterly Results

Operating Income

Operating income was unchanged at $13 million for the three months ended September 30, 2009, compared to the same period in 2008.

Operating Revenues

Operating revenues of $40 million for the three months ended September 30, 2009, were unchanged compared to the same period in 2008, due to:

	•		Energy revenues — increased by $3 million primarily due to a 23% increase in generation in 2009 compared to 2008 offset by a 7% decrease in merchant energy prices.

	•		Capacity revenues — increased by $5 million primarily due to additional resource adequacy contract sales at El Segundo in 2009 compared to 2008.

	•		Other revenues — increased by $1 million due to an increase in ancillary services revenue.

	•		Risk management activities — losses of $9 million were recorded during the quarter including $6 million of unrealized mark-to-market losses and $3 million in realized losses on settled transactions. There was no risk management activity in 2008. For further discussion of the Company’s risk management activities, see Consolidated Results of Operations.

Year-to-Date Results

Operating income decreased by $18 million for the nine months ended September 30, 2009, compared to the same period in 2008, due to decreases in capacity revenue, energy revenue, risk management activity revenue and other revenues.

Operating Revenues

Operating revenues decreased by $17 million for the nine months ended September 30, 2009, compared to the same period in 2008, due to:

	•		Capacity revenues — decreased by $4 million primarily due to expiration of a two year tolling agreement at the El Segundo facility in April 2008, which was replaced by resource adequacy and capacity contracts at lower prices.

	•		Energy revenues — decreased by $3 million primarily due to a 19% decrease in merchant prices in 2009 compared to 2008; offset by a 6% increase in merchant generation in 2009 compared to 2008.

	•		Other revenue — decreased by $4 million primarily due to lower emission allowance sales partially offset by an increase in ancillary services revenue.

	•		Risk management activities — realized losses of $6 million on settled transactions were recognized during the period. There was no risk management activity in 2008. For further discussion of the Company’s risk management activities, see Consolidated Results of Operations.

Cost of Energy and Other Operating Expenses

Cost of energy and other operating expenses increased by $1 million for the nine months ended September 30, 2009, compared to the same period in 2008, due to:

	•		Cost of energy — decreased by $8 million due to a 43% decline in average natural gas prices per MMBtu. This decrease was partially offset by a 7% increase in natural gas consumption and a $2 million increase in fuel oil expense.

	•		Other operating expenses — increased by $9 million due to higher maintenance expense associated with a major overhaul at El Segundo and higher maintenance at Long Beach.

Liquidity and Capital Resources

Liquidity Position

As of September 30, 2009, and December 31, 2008, NRG’s liquidity, excluding collateral received, was approximately $3.9 billion and $3.4 billion, respectively, and comprised of the following:


	September 30,			December 31,
(In millions)	2009			2008

Cash and cash equivalents	$	2,250		$	1,494
Funds deposited by counterparties		293			754
Restricted cash		26			16

Total cash		2,569			2,264
Synthetic Letter of Credit Facility availability		756			860
Revolver Credit Facility availability		904			1,000

Total liquidity		4,229			4,124
Less: Funds deposited as collateral by hedge counterparties		(293	)		(760	)

Total liquidity, excluding collateral received	$	3,936		$	3,364

For the nine months ended September 30, 2009, total liquidity, excluding collateral received, increased by $572 million due to a higher cash balance of $756 million, partially offset by decreased availability of the Synthetic Letter of Credit Facility and the Revolving Credit Facility of $104 million and $96 million, respectively. Changes in cash balances are further discussed below under the heading Cash Flow Discussion. Cash and cash equivalents and funds deposited by counterparties at September 30, 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” represents the amounts that are held by NRG as a result of collateral posting obligations from our counterparties due to positions in our hedging program. These amounts are segregated into separate accounts that are not contractually restricted but, based on the Company’s intention, are not available for the payment of NRG’s general corporate obligations. 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. Since collateral requirements fluctuate daily and the Company cannot predict if any collateral will be held for more than twelve months, the funds deposited by counterparties are classified as a current asset on the Company’s balance sheet, with an offsetting liability for this cash collateral received within current liabilities. The decrease in these amounts from December 31, 2008 was due to cash collateral moved from NRG to Merrill Lynch in connection with novations under the CSRA (see Note 4, Business Acquisition, to this Form 10-Q), offset by an increase of in-the-money positions as a result of decreasing forward prices.

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 September 30, 2009, NRG had 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. On July 23, 2009, Moody’s upgraded the Senior Credit Facility to Baa3 due to the underlying value that the capital structure provides to secured creditors. As of September 30, 2009, NRG had issued $544 million of letters of credit under the Synthetic Letter of Credit Facility, leaving $756 million available for future issuances. Under the Revolving Credit Facility, as of September 30, 2009, NRG had issued a letter of credit of $96 million of which $59 million supports the tax exempt bonds issued by Dunkirk Power LLC as described in Note 8, Long-Term Debt, to this Form 10-Q.

2019 Senior Notes

On June 5, 2009, NRG completed the issuance of $700 million aggregate principal amount of 8.5% Senior Notes due 2019, or 2019 Senior Notes as described in Note 8, Long-Term Debt, to this Form 10-Q. The Company used a portion of the net proceeds of $678 million to facilitate the early termination of NRG’s obligations pursuant to the CSRA Amendment, which became effective October 5, 2009. Net proceeds in excess of this amount are available for general corporate purposes. See further discussion of the CSRA Amendment in Note 20, Subsequent Event, to this Form 10-Q.

Merrill Lynch Credit Sleeve Facility

As of September 30, 2009, Merrill Lynch, through the CSRA with NRG, provided the Company with $163 million in credit support (includes cash collateral posted by counterparties and Reliant Energy as an offset to exposure) that significantly reduced the liquidity requirements and substantially eliminated collateral postings for Reliant Energy. See discussion in Note 4, Business Acquisition, to this Form 10-Q, regarding the CSRA as a result of the acquisition of Reliant Energy on May 1, 2009. Effective October 5, 2009, the Company executed the CSRA Amendment. In connection with this transaction, the Company posted $366 million of cash collateral to Merrill Lynch and other counterparties, returned $53 million of counterparty collateral, issued $206 million of letters of credit, and received $45 million of counterparty collateral. In addition, Merrill Lynch returned $250 million of previously posted cash collateral, and released liens on $322 million of unrestricted cash held by Reliant Energy. See further discussion of the CSRA Amendment in Note 20, Subsequent Event, to this Form 10-Q.

TANE Facility

On February 24, 2009, NINA executed an 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 Units 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 September 30, 2009, no amounts had been borrowed 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 used for 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 proceeds received through September 30, 2009, were $38 million with the remaining balance being released over time as construction costs are paid.

GenConn Energy LLC related financings

In April 2009, a wholly-owned subsidiary of NRG executed 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 covering amounts drawn on the 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 requires mandatory prepayment of the portion of the loan utilized to pay costs of the Devon project, of approximately $56 million, on the earlier of Devon’s commercial operations date or January 27, 2011. The proceeds of the EBL received through September 30, 2009, were $88 million and the remaining amounts will be drawn as necessary to fund construction costs.

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First and Second Lien Structure

NRG has granted first and second liens to certain counterparties on substantially all of the Company’s assets. 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-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-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 its assets to the extent market prices exceed the hedged price. As of September 30, 2009, and October 22, 2009, all hedges under the first and second liens were in-the-money on a counterparty aggregate basis.

The following table summarizes the amount of MWs hedged against the Company’s baseload assets and as a percentage relative to the Company’s forecasted baseload capacity under the first and second lien structure as of October 22, 2009:


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

In MW ^(b)		3,617		3,963		3,060		1,610		793
As a percentage of total forecasted baseload capacity ^(c)		52%		58%		45%		24%		12%


(a)		Equivalent Net Sales include natural gas swaps converted using a weighted average heat rate by region.
(b)		2009 MW value consists of November through December positions only.
(c)		Forecasted baseload capacity under the first and second lien structure represents 80% of the Company’s total baseload assets.

Asset Sales — Disposition of MIBRAG Investment

For its share, NRG received EUR 203 million ($284 million at an exchange rate of 1.40 U.S.$/EUR), net of transaction costs. During the nine months ended September 30, 2009, NRG recognized a pre-tax gain of $128 million. Prior to completion of the sale, NRG continued to record its share of MIBRAG’s operations to “Equity in earnings of unconsolidated affiliates.”

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 September 30, 2009, commercial operations had total cash collateral outstanding of $222 million, and $345 million outstanding in letters of credit to third parties primarily to support its economic hedging activities. As of September 30, 2009, total collateral held from counterparties was $293 million and $19 million of letters of credit. These collateral amounts do not include collateral postings by Merrill Lynch under the CSRA.

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Upon execution of the CSRA Amendment, effective October 5, 2009, the Company is required to post collateral for any net liability derivatives, and other static margin associated with supply for Reliant Energy.

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 September 30, 2009, NRG had issued approximately $5.4 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 $544 million of letters of credit under the Company’s $1.3 billion Synthetic Letter of Credit Facility and $96 million of letters of credit under the Company’s Revolving Credit Facility. The Revolving Credit Facility matures on February 2, 2011, and the Synthetic Letter of Credit Facility matures on February 1, 2013.

As of September 30, 2009, the Company’s CSF I and CSF II subsidiaries had outstanding notes and preferred interests classified as debt that matured in two tranches: $143 million for CSF II in October 2009, plus accrued interest and the balance of $190 million for CSF I in June 2010, plus accrued interest. On October 9, 2009, NRG commenced the process of unwinding the CSF II Debt, making a $181.4 million capital contribution to a CSF II cash account, effectively restricting the cash for the benefit of CS. On October 13, 2009, CS began the process of unwinding their hedges in connection with the CSF II structure, which they are required to complete by November 24, 2009. Once complete, CS is scheduled to return 5,400,000 shares of NRG common stock borrowed under the Share Lending Agreements, and release 9,528,930 common shares held as collateral for the CSF II Debt, and the Company will remit payment to CS of the $181.4 million outstanding principal and interest. The CSF II Debt contains an embedded derivative feature, or CFS II CAGR, which requires NRG to pay 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 of $40.80 per share. On November 24, 2009, the CSF II CAGR will also be evaluated to determine whether any payment is due to CS, at which point the CSF II CAGR will expire.

Capital Expenditures

For the nine months ended September 30, 2009, the Company’s capital expenditures, including accruals, were approximately $556 million, of which $272 million was related to RepoweringNRG projects. The following table summarizes the Company’s capital expenditures for the nine months ended September 30, 2009, and the estimated capital expenditure and repowering investments forecast for the remainder of 2009.


(In millions)	Maintenance		Environmental		Repowering		Total

Northeast	$	22	$	119	$	5	$	146
Texas		112		—		134		246
South Central		3		—		—		3
West		3		—		2		5
Reliant Energy		14		—		—		14
Nuclear development		—		—		130		130
Other		11		—		1		12

Total	$	165	$	119	$	272	$	556

Estimated capital expenditures for the remainder of 2009	$	117	$	76	$	73	$	266

RepoweringNRG capital expenditures and investments — RepoweringNRG project capital expenditures consisted of approximately $104 million related to the Company’s Langford wind farm project which is currently under construction. In addition, the Company’s RepoweringNRG capital expenditures included $29 million for the construction of Cedar Bayou Unit 4 in Texas and $130 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 $73 million. Of this amount, $58 million is estimated for STP Units 3 and 4 without giving effect to any partner contributions or potential equity sell down and approximately $10 million to complete the construction of the Langford wind farm.

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Major maintenance and environmental capital expenditures — The Company’s baghouse projects at western New York facilities resulted in environmental capital expenditures of $104 million for the nine months ended September 30, 2009. In addition, the Company’s maintenance capital expenditures were $165 million, of which $112 million was primarily related to the Texas region’s assets which included approximately $38 million in nuclear fuel expenditures related STP units 1 and 2.

NRG anticipates funding its maintenance capital projects primarily with funds generated from operating activities. In addition, on April 15, 2009, the Company executed a $59 million tax-exempt bond financing through its wholly-owned subsidiary, Dunkirk Power LLC, 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.

Loans to affiliates — The Company had funded approximately $48 million in interest bearing loans to GenConn Energy LLC, a 50/50 joint venture vehicle of NRG and the United Illuminating Company as part of the Devon and Middletown plant repowering projects prior to the closing of the EBL and GenConn Facility. As of September 30, 2009, these loans were repaid with proceeds from the EBL financing. Subsequent to the financing, the equity portion of construction costs for GenConn are funded through the EBLs of NRG Connecticut Peaking and United Illuminating. These funds are made available to GenConn through convertible interest bearing promissory notes that convert to equity upon repayment of the EBL loans by NRG Connecticut Peaking and United Illuminating. As of September 30, 2009, there was $88 million was outstanding under the loan from NRG Connecticut Peaking.

Environmental Capital Expenditures

Based on current rules, technology and plans, NRG has estimated that environmental capital expenditures from 2010 through 2013 to meet NRG’s environmental commitments will be approximately $900 million and are primarily associated with controls on the Company’s Big Cajun and Indian River facilities. 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 U.S. EPA 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. In July 2009, as part of the Company’s 2009 Capital Allocation Program, the Board of Directors approved an increase to the Company’s previously authorized common share repurchases under its capital allocation plan from the existing $330 million to $500 million. The Company’s repurchases during the period ended September 30, 2009, were approximately $250 million. NRG intends to complete its $500 million of share repurchases by the end of 2009, subject to market prices, financial restrictions under the Company’s debt facilities, and as permitted by securities laws.

Preferred Stock Dividend Payments

For the nine months ended September 30, 2009, NRG paid approximately $6 million, $13 million, and $8 million in dividend payments to holders of the Company’s 5.75%, 4%, and 3.625% Preferred Stock, respectively. 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.

Benefit Plans Obligations

As of September 30, 2009, NRG contributed $22 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 $5 million during the remainder of 2009. The total 2009 planned contribution of $27 million is a decrease of $33 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.

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Reliant Energy Customer Deposits

Changes in the Texas law will require customer deposits and advance payments to be held in a segregated cash account on or before May 21, 2010. The amount of deposits subject to segregation at September 30, 2009, was approximately $56 million.

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)
Nine months ended September 30,	2009			2008			Change

Net cash provided by operating activities	$	1,280		$	1,086		$	194
Net cash used by investing activities		(727	)		(332	)		(395	)
Net cash provided by/(used by) financing activities		200			(446	)		646

Net Cash Provided By Operating Activities

For the nine months ended September 30, 2009, net cash provided by operating activities increased by $194 million compared to the same period in 2008, due to:

	•		Cash generated by Reliant Energy — Reliant Energy contributed approximately $370 million to the Company’s consolidated cash flow from operations in 2009, primarily reflecting $807 million in pre-tax income since the May 1, 2009, acquisition date. This contribution from pre-tax income was offset by $250 million in collateral postings to satisfy obligations under the CSRA. In addition, a seasonal increase in accounts receivable of $174 million and a $68 million decrease in accrued expenses and other current liabilities also negatively impacted Reliant Energy’s cash flow from operations.

	•		Lower cash flows from Wholesale Power Generation — The Company’s cash flow from operation excluding Reliant Energy was lower by approximately $176 million in 2009 compared to 2008, as drops in generation and power prices impacted results from operation. In addition, $15 million more cash was used for working capital in 2009 compared to 2008, as higher coal inventory balances were partially offset by $35 million lower pension contributions. The reductions to cash flows were partially offset by the return of collateral deposits from the settlement of gas options during the first quarter of 2009 which resulted in a $97 million net inflow of cash.

Net Cash Used By Investing Activities

For the nine months ended September 30, 2009, net cash used in investing activities increased by $395 million compared to the same period in 2008, due to:

	•		Acquisition of Reliant Energy — During the nine months ended September 30, 2009, the Company paid $356 million, net of cash acquired of $6 million, towards its acquisition of Reliant Energy. This amount was comprised of approximately $288 million paid at closing, as well as $63 million paid on June 11, 2009, and $11 million paid on July 24, 2009, as initial remittances of the acquired working capital to RRI.

	•		Trading of emission allowances — Net purchases and sales of emission allowances resulted in a decrease in cash of $117 million for 2009 as compared to 2008.

	•		Proceeds from sale of equity method investment and discontinued operations — Net proceeds from investing activities increased by $43 million in 2009 as compared to 2008 due to the sale of MIBRAG in June 2009 for net proceeds of $284 and the sale of ITISA for proceeds, net of divested cash, of $241 million in the first half of 2008.

	•		Capital expenditures and loans to affiliates — NRG’s capital expenditures decreased by $89 million due to decreased spending on RepoweringNRG projects. Loans to affiliates increased by $37 million in 2009 as compared to 2008.

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Net Cash Provided By/Used By Financing Activities

For the nine months ended September 30, 2009, net cash provided by financing activities increased by $646 million compared to 2008, due to:

	•		Issuance of debt — During 2009, the Company received $25 million from the draw under the Reliant Energy working capital facility with Merrill Lynch, $38 million from the Dunkirk bonds, $88 million in GenConn financings and $688 million in gross proceeds from the 2019 Senior Notes. During 2008, the Company received $20 million in proceeds from borrowings.

	•		Deferred financing costs — During 2009, the Company paid deferred financing costs of $15 million related to the Reliant Energy CSRA, $10 million related to the 2019 Senior Notes, and $2 million related to the Dunkirk bonds and the Reliant Energy working capital facility.

	•		Term Loan Facility debt payment — In 2009, the Company paid down $221 million of its Term Loan Facility, including the payment of excess cash flow, as discussed above under Debt Service Obligations. The Company paid down $166 million of its Term Loan Facility during 2008 which resulted in a net cash decrease of $55 million.

	•		Share repurchase — During 2009, the Company repurchased common stock of $250 million as compared to $185 million in 2008, which resulted in a net cash decrease of $65 million.

	•		Net payments to settle acquired derivatives that include financing elements— In 2009, the Company paid a net of $140 million for the settlement of gas swaps related to Reliant Energy and Texas Genco compared to a payment of $49 million for 2008 related to Texas Genco for a net decrease in cash of $91 million.

	•		Payment for CSF I CAGR settlement — In August 2008, the Company paid $45 million to CS for the benefit of CSF I to early settle the embedded derivative in the Company’s CSF I notes and preferred interests.

	•		Exercise of stock options — During 2009, the Company received proceeds of $1 million from the exercise of stock options as compared to $8 million for 2008.

	•		Preferred dividends — During the nine months ended September 30, 2009, dividends payments on preferred stock decreased by $14 million as compared to the same period in 2008 due to the conversion of the 5.75% preferred stock in the fourth quarter of 2008 and for the period ended September 30, 2009.

NOLs, Deferred Tax Assets and Uncertain Tax Position Implications, under ASC-740, Income Taxes, or ASC 740

As of September 30, 2009, the Company had generated total domestic pre-tax book income of $1,371 million and foreign continuing pre-tax book income of $151 million. The Company has net operating losses for tax return purposes that have been classified as capital loss carryforwards for financial statement purposes and for which a full valuation allowance has been established. In addition, NRG has cumulative foreign NOL carryforwards of $290 million, of which $83 million will expire starting in 2011 through 2018 and of which $207 million do not have an expiration date. As a result of the Company’s tax position, and based on current forecasts, the Company anticipates income tax payments of up to $75 million during 2009.

However, as the position remains uncertain, the Company has recorded a non-current tax liability of $688 million. The $688 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.

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New and On-going Company Initiatives

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.

The 2009 FORNRG goal is a 20 basis point improvement in ROIC which corresponds to approximately $30 million in cash flow. As of September 30, 2009, the Company has exceeded its 2009 goal with a 29.5 basis point improvement in ROIC, which is equivalent to approximately $44 million in cash flows. The performance of the plants coupled with strategic projects undertaken by corporate functions is evidenced in the overall corporate performance.

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. On May 1, 2009, TANE made the second of its scheduled $50 million contributions to NINA.

The Department of Energy, or DOE, has confirmed that STP Units 3 and 4 is one of four projects selected for further due diligence and negotiation leading to a conditional commitment under the DOE loan guarantee program. NINA will now begin discussions with the DOE on the specific terms and amount to be loaned for the project. NRG believes DOE loan guarantee support is critical to new nuclear development projects. In addition to U.S. loan guarantees, NINA is seeking to diversify financing by actively pursuing additional loan guarantees through the Japanese government. Due diligence by Japanese financing agencies is in progress and represents an important step in Japanese loan support.

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 NSR 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.

A request to intervene in the Combined License, or COL, proceeding was submitted by several individuals and public interest groups on April 21, 2009. An Atomic Licensing and Safety Board, or Licensing Board, heard oral arguments on the Petitioner’s request for a hearing on June 23, 2009, and June 24, 2009, in Bay City, Texas. On August 27, 2009, and September 29, 2009, the Licensing Board of the United States Nuclear Regulatory Commission, or NRC, issued its decision on the petition to intervene in the COL proceeding for STP Units 3 and 4. Of the 28 contentions submitted by the Petitioner’s, the Licensing Board rejected 23 and admitted a portion of five contentions. The Licensing Board’s decision to admit a contention represents a procedural ruling only. The ruling does not reflect any decision on the merits of any admitted contention by the Licensing Board. NINA will continue to defend its position against the admitted contentions in future hearings.

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On October 22, 2009, NINA amended its revolving credit agreement with the Royal Bank of Scotland PLC, or RBS. The amended agreement allows for NINA to have borrowings outstanding on both its RBS facility and its TANE facility. Under the new agreement NINA will be required to repay all outstanding balances on the RBS facility by March 31, 2010.

Agreement with eSolar

On June 1, 2009, NRG completed an agreement with eSolar, a leading provider of modular, scalable solar thermal power technology, to acquire the development rights for solar thermal power plants at sites in California and the Southwest. The agreement currently contemplates up to 465 MW of solar thermal development. The first plant is anticipated to begin producing electricity as early as 2011, subject to certain technology demonstration milestones being pursued by eSolar and successful financial closing in 2010. At the closing with eSolar, NRG invested approximately $5 million for an equity interest in eSolar and $5 million for deposits and land purchase options associated with development rights for three projects on sites in south central California and the Southwest U.S. as well as a portfolio of PPAs to develop, build, own and operate up to 10 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.

NRG has three projects in various stages of development: NRG New Mexico SunTower, Alpine SunTower and Desert View SunTower. While each of these projects has an anticipated commercial operation date, the development of these projects are subject to certain conditions and milestones which may effect the Company’s decision to pursue further development of these projects.

RepoweringNRG Update

Currently, NRG has several projects in varying stages of development that include the following: a solar project with the City of Houston, a biomass project at the Montville Generating Station, a new generating unit at the Limestone power station and the repowering of Big Cajun I, Encina and El Segundo sites. 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.

Plants Completed and Operating

Cedar Bayou Generating Station — On June 24, 2009, NRG and Optim Energy, LLC, or Optim Energy, completed construction and began commercial operation of a new natural gas-fueled combined cycle generating plant at NRG’s Cedar Bayou Generating Station in Chambers County, Texas. NRG and Optim Energy have a 50/50 undivided interest basis in the 550 MW generating plant. NRG is the operator of the plant and Optim Energy is acting as energy manager for Cedar Bayou unit 4. Cedar Bayou unit 4 is providing the Company a net capacity of 275 MW given NRG’s 50% ownership.

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 Energy, 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 eight GE LM6000 combustion turbines required for the projects. Construction has begun at the Devon facility while site demolition has begun at the Middletown location.

On April 27, 2009, GenConn Energy closed on $534 million of project financing related to these projects. The project financing includes a seven-year project backed term loan and a five year working capital facility which together total $291 million. In addition, NRG and United Illuminating have each closed an equity bridge loan of $121.5 million, which together total $243 million. NRG is funding its share of costs related to these projects via year to date draw downs on the equity bridge loan of $88 million as of September 30, 2009. In August 2009, GenConn began to draw on the project financing facility to cover costs related to the Devon project.

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Langford Wind Project — On March 16, 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 and is expected to be eligible to qualify for a cash grant from the Department of Treasury.

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 18, Guarantees, to this Form 10-Q for additional discussion.

See discussion in Note 4, Business Acquisition, to this Form 10-Q, regarding the CSRA as a result of the acquisition of Reliant Energy on May 1, 2009.

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 ASC 815. Although it is considered an embedded derivative, it is exempt from derivative accounting as it is excluded from the scope pursuant to ASC 815. As of September 30, 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 as defined in ASC 815. Although it is considered a derivative, it is exempt from derivative accounting as it is excluded from the scope of ASC 815. As of September 30, 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 September 30, 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 $77 million as of September 30, 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 15, 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 nine months ended September 30, 2009.

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Critical Accounting Policies and Estimates

NRG’s discussion and analysis of the financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. 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 and 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.

In connection with the Reliant Energy acquisition, the Company will record additional intangible assets. See Note 4, Business Acquisition, to this Form 10-Q. In addition, accrued unbilled revenues related to the Reliant Energy segment are critical accounting estimates as volumes are not precisely known at the end of each reporting period and the revenue amounts are material. Accrued unbilled revenues were $321 million as of September 30, 2009, which represents 5% of the Company’s consolidated revenues for the nine months ended September 30, 2009, and 11% of Reliant Energy’s revenues for the period ended September 30, 2009. Accrued unbilled revenues are based on Reliant Energy’s estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Volume estimates are based on daily forecasted volumes and estimated customer usage by class. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class. Estimated amounts are adjusted when actual usage is known and billed.

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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, liquidity risk, credit 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, volatilities, 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 a result of the acquisition of Reliant Energy, NRG’s portfolio consists of generation assets and full requirement load serving obligations. NRG manages the commodity price risk of the Company’s merchant generation operations and load serving obligations by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted sales and purchases of electricity and 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, operations 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 concept that defines risk of loss, at a certain confidence level, over a designated horizon due to changes in market prices over that horizon. Currently, the company estimates VaR using a Monte Carlo simulation of prices. 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) a 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 September 30, 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 $53 million. The inclusion of the Reliant Energy retail portfolio, comprised of contracted load and related supply, did not materially affect the VaR measure as the portfolio is currently hedged.

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The following table summarizes average, maximum and minimum VaR for NRG for the three and nine months ended September 30, 2009, and 2008:


(In millions)
VAR	2009		2008

Three months ended September 30:	$	53	$	51
Average		49		48
Maximum		55		62
Minimum		42		35

Nine months ended September 30:	$	53	$	51
Average		42		50
Maximum		55		65
Minimum		28		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 September 30, 2009, for the entire term of these instruments entered into for both asset management and trading, was approximately $26 million primarily driven by asset-backed transactions.

Interest Rate Risk

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

As of September 30, 2009, the Company had various interest rate swap agreements with notional amounts totaling approximately $3.3 billion. If the swaps had been discontinued on September 30, 2009, the Company would have owed the counterparties approximately $124 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 September 30, 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 September 30, 2009, the Company’s long-term debt fair value was $8.4 billion and the carrying amount was $8.6 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 $435 million.

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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 for power and gas positions under marginable contracts excluding all non-affiliate third party positions under the CSRA, a $1 per MMBtu change in natural gas prices across the term of the marginable contracts would cause a change in margin collateral posted of approximately $73 million as of September 30, 2009, and a 0.25 MMBtu/MWh change in heat rates for heat rate positions would result in a change in margin collateral posted of approximately $53 million as of September 30, 2009. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of September 30, 2009.

With the CSRA Amendment, effective October 5, 2009, based on a sensitivity analysis for power and gas positions under marginable contracts, a $1 per MMBtu change in natural gas prices across the term of the marginable contracts would cause a change in margin collateral posted of approximately $164 million, and a $0.25 MMBtu/MWh change in heat rate positions would result in a change in margin collateral posted of approximately $69 million. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of October 5, 2009.

Under the second lien, NRG is required to post certain letters of credit as credit support for changes in commodity prices. As of September 30, 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

Since the credit crisis began in late 2008, the Company has taken several additional steps to mitigate credit risk including the use of netting arrangements, entering contracts with collateral thresholds, setting volumetric limits with certain counterparties and restricting trading relationships with counterparties where exposure was high or where credit quality of the counterparty had deteriorated. 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.

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	Net Exposure ^(a) (b)
	as of September 30, 2009
Category	(% of Total)

Financial institutions		81	%
Utilities, energy, merchants, marketers and other		13
Coal suppliers		3
ISOs		3

Total		100	%


	Net Exposure ^(a) (b)
	as of September 30, 2009
Category	(% of Total)

Investment grade		93	%
Non-Investment grade		2
Non-rated		5

Total		100	%


(a)		Credit exposure excludes California tolling, uranium, coal transportation, New England Reliability Must-Run, cooperative load contracts, and Texas Westmoreland coal contracts. The aforementioned exposures were excluded for various reasons including regulatory support or liens held against the contracts which serve to reduce the risk of loss, or credit risks for certain contracts are not readily measurable due to a lack of market reference prices.

(b)		The exposure amounts presented in the above table do not include non-affiliate third party exposure under the CSRA. The gross credit exposure to third parties under the CSRA is $385 million, and the cash collateral held by Merrill Lynch against this exposure is $304 million.

NRG is exposed to retail credit risk through its competitive electricity supply business, which serves commercial and industrial customers and the mass market in Texas. Retail credit risk results when a customer fails to pay for services rendered. The losses could be incurred from nonpayment of customer accounts receivable and any in-the-money forward value. NRG manages retail credit risk through the use of established credit policies that include monitoring of the portfolio, and the use of credit mitigation measures such as deposits or prepayment arrangement. Retail credit risk is dependent on the overall economy, but is minimized due to the fact that NRG’s portfolio of retail customers is largely diversified, with no significant single name concentration.

Fair Value of Derivative Instruments

NRG may enter into long-term power purchase and 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, hedge supplies for retail operations 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.

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The tables below disclose the activities that include both exchange and non-exchange traded contracts accounted for at fair value in accordance with ASC 820. 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 September 30, 2009, based on their level within the fair value hiearchy defined in ASC 820; and indicate the maturities of contracts at September 30, 2009. Also, in connection with the Company’s acquisition of Reliant Energy, NRG acquired retail load and supply contracts. The table below also includes the fair value of supply contracts under mark-to-market accounting treatment as of May 1, 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		(375	)
Contracts acquired in conjunction with Reliant Energy		(1,054	)
Changes in fair value		795

Fair value of contracts as of September 30, 2009	$	362


	Fair Value of Contracts as of September 30, 2009
	Maturity									Maturity
(In millions)	Less Than			Maturity			Maturity			in Excess			Total Fair
Fair value hiearchy gains/(losses)	1 Year			1-3 Years			4-5 Years			4-5 Years			Value

Level 1	$	5		$	4		$	(1	)	$	—		$	8
Level 2		204			131			120			(31	)		424
Level 3		(27	)		(43	)		—			—			(70	)

Total	$	182		$	92		$	119		$	(31	)	$	362

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. A significant portion of the fair value of the Company’s derivative portfolio is based on price quotes from brokers in active markets who regularly facilitate our transactions and we believe such price quotes are executable. We do not use third party sources that derive price based on proprietary models or market surveys. The remainder of the assets and liabilities represents 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 19% 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 uses the counterparty’s default swap rate. If the exposure under a specific master agreement is a liability, the Company uses 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 September 30, 2009, the credit reserve resulted in a $18 million increase in fair value which is composed of a $4 million gain in OCI and a $14 million gain in derivative revenue and cost of operations.

The fair values in each category reflect the level of forward prices and volatility factors as of September 30, 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 in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, NRG measures the sensitivity of the Company’s portfolio to potential changes in market prices using 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 September 30, 2009, NRG’s net derivative asset was $362 million, a decrease to total fair value of $634 million as compared to December 31, 2008. This decrease was primarily driven by the acquisition of Reliant Energy’s retail portfolio offset by increase in fair value due to the decreases in gas and power prices and the roll-off of trades that settled during the period.

Based on a sensitivity analysis, the impact of a $1 per MMBtu increase or decrease in natural gas prices across the term of the derivative contracts would cause a change of approximately $574 million in the value of derivatives as of September 30, 2009.

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Currency Exchange Risk

NRG may be subject to foreign currency exchange 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 September 30, 2009, there were no foreign currency options or forward contracts outstanding for purchase commitments.

In connection with the MIBRAG sale transaction, NRG entered into a foreign currency forward contract to hedge the impact of exchange rate fluctuations on the sale proceeds. The foreign currency forward contract had a fixed exchange rate of 1.277 and required NRG to deliver EUR 200 million in exchange for $255 million on June 15, 2009. For the nine months ended September 30, 2009, NRG recorded an exchange loss of $24 million on the contract within “Other income/(expense).”

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 and nine months ended September 30, 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 Control over Financial Reporting

There were no changes in the Company’s internal controls over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred in the third quarter 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 control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with generally accepted accounting principles. However, internal control 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.

115

PART II — OTHER INFORMATION

ITEM 1 — LEGAL PROCEEDINGS

For a discussion of material legal proceedings in which NRG was involved through September 30, 2009, see Note 15, Commitments and Contingencies, to the condensed consolidated financial statements of this Form 10-Q.

ITEM 1A — RISK FACTORS

Information regarding risk factors appears in Part I, Item 1A, Risk Factors in NRG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008 and Part II, Item 1A, Risk Factors in NRG’s Quarterly Report on Form 10-Q for the quarters ended March 31, 2009 and June 30, 2009.

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


							Dollar value of
					Total number of shares		shares that may be
					purchased as part of		purchased under the
	Total number of		Average price		publicly announced		2009 Capital Allocation
For the period ended September 30, 2009	shares purchased		paid per share		plans or programs		Plan

First quarter 2009		—	$	—		—	$	330,000,000
Second quarter 2009		—		—		—		330,000,000

July 1 – July 31		—		—		—		500,000,000
August 1 – August 31		8,477,000		28.09		8,477,000		261,753,846
September 1 – September 30		442,100		26.57		442,100		250,002,565

Third quarter 2009 Total		8,919,100		28.01		8,919,100		250,002,565

Year-to-date		8,919,100	$	28.01		8,919,100	$	250,002,565

In July 2009, as part of the Company’s 2009 Capital Allocation Program, NRG’s Board of Directors approved an increase to the Company’s previously authorized common share repurchases under its capital allocation plan from the existing $330 million to $500 million. The Company’s repurchases during the period ended September 30, 2009, were approximately $250 million. NRG intends to complete its $500 million of share repurchases by the end of 2009, subject to market prices, financial restrictions under the Company’s debt facilities, and as permitted by securities laws.

ITEM 3 — DEFAULTS UPON SENIOR SECURITIES

None.

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

The stockholders of NRG Energy, Inc. voted on nine items at the Annual Meeting of Stockholders held on July 21, 2009:

	1.		The election of Class III Directors to a three-year term;

	2.		The proposal to adopt the NRG Energy, Inc. Amended and Restated Long-Term Incentive Plan;

	3.		The proposal to adopt the NRG Energy, Inc. Amended and Restated Annual Incentive Plan for Designated Corporate Officers;

	4.		The proposal to approve the amendment to Article Six of the Amended and Restated Certificate of Incorporation;

	5.		The proposal to ratify the appointment of KPMG LLP as NRG’s independent registered public accounting firm;

	6.		The stockholder proposal to prepare a report on the Carbon Principles;

	7.		Exelon Corporation’s proposal to approve an amendment to the NRG Bylaws to increase the size of the NRG Board to 19 members;

	8.		If proposal 7 was approved, Exelon’s proposal to elect five Exelon nominees to serve as a director of NRG Board; and

	9.		Exelon’s proposal to repeal any Bylaw amendments adopted by the NRG Board without stockholder approval after February 26, 2008 and prior to the effectiveness of the resolution effecting such repeal.

There were 265,646,655 shares of common and preferred stock entitled to vote at the meeting and a total of 234,133,623 shares (approximately 88%) were represented at the meeting.

116

The four NRG nominees named below were elected to serve a three-year term as Class III Directors expiring at the annual meeting of stockholders in 2012, while the four Exelon nominees named below were defeated:


NRG Nominee	Votes For		Votes Withheld

John F. Chlebowski		175,973,764		691,844
Howard E. Cosgrove		176,009,097		656,511
William E. Hantke		176,018,113		647,495
Anne C. Schaumburg		176,019,858		645,750


Exelon Nominee	Votes For		Votes Withheld

Betsy S. Atkins		57,258,080		209,935
Ralph E. Faison		57,256,776		211,239
Coleman Peterson		57,256,676		211,339
Thomas C. Wajnert		57,256,726		211,289

The names of the directors whose terms as directors continued after the meeting are as follows:

	•		Class I: Kirbyjon H. Caldwell, David Crane, Stephen L. Cropper, Kathleen A. McGinty, Thomas W. Weidemeyer

	•		Class II: Lawrence S. Coben, Paul W. Hobby, Gerald Luterman, Herbert H. Tate, Walter R. Young

The proposal to adopt the NRG Energy, Inc. Amended and Restated Long-Term Incentive Plan was approved with 225,514,895 shares voting for, 4,790,467 shares voting against, and 3,828,260 shares abstaining.

The proposal to adopt the NRG Energy, Inc. Amended and Restated Annual Incentive Plan for Designated Corporate Officers was approved with 228,716,330 shares voting for, 1,578,602 shares voting against, and 3,838,682 shares abstaining.

The proposal to approve the amendment to Article Six of the Amended and Restated Certificate of Incorporation was approved with 227,053,518 shares voting for, 3,098,376 shares voting against, and 3,981,728 shares abstaining.

The proposal to ratify the appointment of KPMG LLP as independent registered public accounting firm was ratified with 229,676,224 shares voting for, 653,217 shares voting against, 3,804,181 shares abstaining.

The stockholder proposal to prepare a report on the Carbon Principles was defeated with 189,432,665 shares voting against, 2,553,249 voting for, and 42,147,708 abstaining.

Exelon Corporation’s proposal to approve an amendment to the NRG Bylaws to increase the size of the NRG Board to 19 members was defeated with 179,032,706 shares voting against, 54,982,954 shares voting for, and 117,963 abstaining. As a result of the defeat of this proposal, Exelon’s proposal to elect five additional Exelon nominees to serve as a director of the NRG Board was rendered moot.

Exelon’s proposal to repeal any Bylaw amendments adopted by the NRG Board without stockholder approval after February 26, 2008 and prior to the effectiveness of the resolution effecting such repeal was defeated with 195,842,708 shares voting against, 38,084,601 shares voting for, and 206,313 abstaining. Regardless of the vote outcome, NRG did not initiate any amendments to the Bylaws during the reference period.

ITEM 5 — OTHER INFORMATION

None.

117

ITEM 6 — EXHIBITS


Exhibits

4.1		Twenty-Third Supplemental Indenture, dated July 14, 2009, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York. ⁽¹⁾

4.2		Twenty-Fourth Supplemental Indenture, dated October 5, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York. ⁽²⁾

4.3		Twenty-Fifth Supplemental Indenture, dated October 5, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.⁽²⁾

4.4		Twenty-Sixth Supplemental Indenture, dated October 5, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.⁽²⁾

4.5		Twenty-Seventh Supplemental Indenture, dated October 5, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.⁽²⁾

10.1A		Amended and Restated Credit Sleeve and Reimbursement Agreement, dated September 30, 2009 (effective October 5, 2009), among Reliant Energy Power Supply, LLC, RERH Holdings, LLC, Reliant Retail Holdings, LLC, Reliant Energy Retail Services, LLC, RE Retail Renewables, LLC, Merrill Lynch Commodities, Inc. and Merrill Lynch & Co., Inc.

10.1B		Schedules and Exhibits to the Amended and Restated Credit Sleeve and Reimbursement Agreement, dated September 30, 2009 (effective October 5, 2009) (Portions of this Exhibit have been omitted pursuant to a request for confidential treatment).

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.

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema

101.CAL		XBRL Taxonomy Extension Calculation Linkbase

101.DEF		XBRL Taxonomy Extension Definition Linkbase

101.LAB		XBRL Taxonomy Extension Label Linkbase

101.PRE		XBRL Taxonomy Extension Presentation Linkbase


(1)		Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on July 15, 2009.

(2)		Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on October 6, 2009.

118

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)
By:
		/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: November 2, 2009		Chief Accounting Officer (Principal Accounting Officer)

119

EXHIBIT INDEX


Exhibits

4.1		Twenty-Third Supplemental Indenture, dated July 14, 2009, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York. ⁽¹⁾

4.2		Twenty-Fourth Supplemental Indenture, dated October 5, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York. ⁽²⁾

4.3		Twenty-Fifth Supplemental Indenture, dated October 5, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.⁽²⁾

4.4		Twenty-Sixth Supplemental Indenture, dated October 5, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.⁽²⁾

4.5		Twenty-Seventh Supplemental Indenture, dated October 5, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.⁽²⁾

10.1A		Amended and Restated Credit Sleeve and Reimbursement Agreement, dated September 30, 2009, among Reliant Energy Power Supply, LLC, RERH Holdings, LLC, Reliant Retail Holdings, LLC, Reliant Energy Retail Services, LLC, RE Retail Renewables, LLC, Merrill Lynch Commodities, Inc. and Merrill Lynch & Co., Inc.

10.1B		Schedules and Exhibits to the Amended and Restated Credit Sleeve and Reimbursement Agreement, dated September 30, 2009 (effective October 5, 2009) (Portions of this Exhibit have been omitted pursuant to a request for confidential treatment).

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.

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema

101.CAL		XBRL Taxonomy Extension Calculation Linkbase

101.DEF		XBRL Taxonomy Extension Definition Linkbase

101.LAB		XBRL Taxonomy Extension Label Linkbase

101.PRE		XBRL Taxonomy Extension Presentation Linkbase


(1)		Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on July 15, 2009.

(2)		Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on October 6, 2009.

120