Edgar Filing: NRG ENERGY, INC.

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

For the quarterly period ended: September 30, 2010


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

Commission File Number: 001-15891

NRG Energy, Inc.

(Exact name of registrant as specified in its charter)


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

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such 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):


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

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

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 November 1, 2010, there were 247,197,248 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			8
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES			8
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			49
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			86
ITEM 4 — CONTROLS AND PROCEDURES			88
PART II — OTHER INFORMATION			89
ITEM 1 — LEGAL PROCEEDINGS			89
ITEM 1A — RISK FACTORS			89
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			89
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES			89
ITEM 4 — (REMOVED AND RESERVED)			89
ITEM 5 — OTHER INFORMATION			90
ITEM 6 — EXHIBITS			91
SIGNATURES			92
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 of NRG Energy, Inc., or NRG or the Company, 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, 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 revenues;

•

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

•

Reliant Energy’s ability to maintain market share;

•

NRG’s ability to successfully evaluate investments in new business and growth initiatives; and

•

NRG’s ability to successfully integrate and manage acquired businesses.

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:


2009 Form 10-K		NRG’s Annual Report on Form 10-K for the year ended December 31, 2009

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

CAA		Clean Air Act

CAIR		Clean Air Interstate Rule

CAISO		California Independent System Operator

CATR		Clean Air Transport Rule

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

C&I		Commercial, industrial and governmental/institutional

CFTC		U.S. Commodity Futures Trading Commission

CO₂		Carbon dioxide

CPS		CPS Energy

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

CSRA Amendment		Amendment of the existing CSRA with Merrill Lynch which became effective October 5, 2009

DNREC		Delaware Department of Natural Resources and Environmental Control

ERCOT		Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas

Exchange Act		The Securities Exchange Act of 1934, as amended

FASB		Financial Accounting Standards Board — the designated organization for establishing standards for financial accounting and reporting

FERC		Federal Energy Regulatory Commission

Funded Letter of Credit Facility		NRG’s $1.3 billion term loan-backed fully funded senior secured letter of credit facility, of which $500 million matures on February 1, 2013, and $800 million matures on August 31, 2015, and is a component of NRG’s Senior Credit Facility

GHG		Greenhouse Gases

GWh		Gigawatt hour

IGCC		Integrated Gasification Combined Cycle

ISO		Independent System Operator, also referred to as Regional Transmission Organizations, or RTO

ISO-NE		ISO New England Inc.

kW		Kilowatts

kWh		Kilowatt-hours


LIBOR		London Inter-Bank Offer Rate

LTIP		Long-Term Incentive Plan

MACT		Maximum Achievable Control Technology

Mass		Residential and small business

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

MW		Megawatts

MWh		Saleable megawatt hours net of internal/parasitic load megawatt-hours

NAAQS		National Ambient Air Quality Standards

NINA		Nuclear Innovation North America LLC

NO_x		Nitrogen oxide

NPNS		Normal Purchase Normal Sale

NRC		U.S. Nuclear Regulatory Commission

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

PM 2.5		Particulate matter particles with a diameter of 2.5 micrometers or less

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

RERH		RERH Holding, LLC and its subsidiaries

Revolving Credit Facility		NRG’s $875 million senior secured revolving credit facility, which matures on August 31, 2015, and is a component of NRG’s Senior Credit Facility

RGGI		Regional Greenhouse Gas Initiative

RMR		Reliability Must-Run

ROIC		Return on invested capital

RRI		RRI Energy, Inc. (formerly Reliant Energy, Inc.)

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, an $875 million Revolving Credit Facility and a $1.3 billion Funded Letter of Credit Facility

Senior Notes		The Company’s $6.5 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, $700 million of 8.5% senior notes due 2019 and $1.1 billion of senior notes due 2020

SO₂		Sulfur dioxide

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

TANE		Toshiba America Nuclear Energy Corporation

TANE Facility		NINA’s $500 million credit facility with TANE which matures on February 24, 2012

TEPCO		The Tokyo Electric Power Company of Japan, Inc.

Term Loan Facility		A senior first priority secured term loan, of which approximately $975 million matures on February 1, 2013, and $1.0 billion matures on August 31, 2015, and is a component of NRG’s Senior Credit Facility

TNEA		TEPCO Nuclear Energy America LLC

Tonnes		Metric tonnes, which are units of mass or weight in the metric system each equal to 2,205lbs and are the global measurement for GHG

TWh		Terawatt hour

U.S.		United States of America

U.S. DOE		United States Department of Energy

U.S. EPA		United States Environmental Protection Agency

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

VaR		Value at Risk

ACCOUNTING PRONOUNCEMENTS

The FASB has established the FASB Accounting Standards Codification, or ASC, as the source of authoritative U.S. GAAP. The FASB issues updates to the ASC through Accounting Standards Updates, or ASUs. The following ASC topics and ASUs are referenced in this report:


ASC 280		ASC-280, Segment Reporting

ASC 450		ASC-450, Contingencies

ASC 740		ASC-740, Income Taxes

ASC 805		ASC-805, Business Combinations

ASC 810		ASC-810, Consolidation

ASC 815		ASC-815, Derivatives and Hedging

ASC 820		ASC-820, Fair Value Measurements and Disclosures

ASC 980		ASC-980, Regulated Operations

ASU 2009-15		ASU No. 2009-15, Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing

ASU 2009-17		ASU No. 2009-17, Consolidations: Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities

ASU 2010-02		ASU No. 2010-02, Consolidation (Topic 810): Accounting and Reporting for Decreases in Ownership of a Subsidiary—a Scope Clarification

ASU 2010-06		ASU No. 2010-06, Fair Value Measurement and Disclosures: Improving Disclosures about Fair Value Measurements

ASU 2010-09		ASU No. 2010-09, Subsequent Events (Topic 815): Amendments to Certain Recognition and Disclosure Requirements

ASU 2010-10		ASU No. 2010-10, Consolidation (Topic 810): Amendments for Certain Investment Funds

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)	2010			2009			2010			2009

Operating Revenues
Total operating revenues	$	2,685		$	2,916		$	7,033		$	6,811

Operating Costs and Expenses
Cost of operations		1,835			1,893			4,803			3,901
Depreciation and amortization		210			212			620			594
Selling, general and administrative		172			182			441			396
Acquisition-related transaction and integration costs		—			6			—			41
Development costs		14			12			36			34

Total operating costs and expenses		2,231			2,305			5,900			4,966
Gain on sale of assets		—			—			23			—

Operating Income		454			611			1,156			1,845

Other Income/(Expense)
Equity in earnings of unconsolidated affiliates		16			6			41			33
Gain on sale of equity method investment		—			—			—			128
Other income/(expense), net		11			5			34			(9	)
Interest expense		(169	)		(178	)		(469	)		(475	)

Total other expense		(142	)		(167	)		(394	)		(323	)

Income Before Income Taxes		312			444			762			1,522
Income tax expense		89			166			271			614

Net Income		223			278			491			908
Less: Net loss attributable to noncontrolling interest		—			—			(1	)		(1	)

Net income attributable to NRG Energy, Inc.		223			278			492			909

Dividends for preferred shares		2			6			7			27

Income available for NRG Energy, Inc. common stockholders	$	221		$	272		$	485		$	882

Earnings per share attributable to NRG Energy, Inc. common stockholders
Weighted average number of common shares outstanding — basic		252			249			254			247
Net income per weighted average common share — basic	$	0.88		$	1.09		$	1.91		$	3.58
Weighted average number of common shares outstanding — diluted		253			272			255			274
Net income per weighted average common share — diluted	$	0.87		$	1.02		$	1.90		$	3.29

See notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS


	September 30, 2010			December 31, 2009
(In millions, except shares)	(unaudited)

ASSETS
Current Assets
Cash and cash equivalents	$	3,447		$	2,304
Funds deposited by counterparties		457			177
Restricted cash		19			2
Accounts receivable — trade, less allowance for doubtful accounts of $35 and $29, respectively		904			876
Inventory		463			541
Derivative instruments valuation		2,479			1,636
Cash collateral paid in support of energy risk management activities		477			361
Prepayments and other current assets		250			311

Total current assets		8,496			6,208

Property, plant and equipment, net of accumulated depreciation of $3,606 and $3,052, respectively		11,844			11,564

Other Assets
Equity investments in affiliates		510			409
Note receivable — affiliate and capital leases, less current portion		402			504
Goodwill		1,713			1,718
Intangible assets, net of accumulated amortization of $948 and $648, respectively		1,541			1,777
Nuclear decommissioning trust fund		389			367
Derivative instruments valuation		1,001			683
Restricted cash supporting funded letter of credit facility		1,301			—
Other non-current assets		222			148

Total other assets		7,079			5,606

Total Assets	$	27,419		$	23,378

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	157		$	571
Accounts payable		765			697
Derivative instruments valuation		2,072			1,473
Deferred income taxes		381			197
Cash collateral received in support of energy risk management activities		457			177
Accrued expenses and other current liabilities		650			647

Total current liabilities		4,482			3,762

Other Liabilities
Long-term debt and capital leases		9,063			7,847
Funded letter of credit		1,300			—
Nuclear decommissioning reserve		313			300
Nuclear decommissioning trust liability		256			255
Deferred income taxes		1,747			1,783
Derivative instruments valuation		500			387
Out-of-market contracts		235			294
Other non-current liabilities		1,054			806

Total non-current liabilities		14,468			11,672

Total Liabilities		18,950			15,434

3.625% convertible perpetual preferred stock (at liquidation value, net of issuance costs)		248			247
Commitments and Contingencies
Stockholders’ Equity
Preferred stock (at liquidation value, net of issuance costs)		—			149
Common stock		3			3
Additional paid-in capital		5,316			4,948
Retained earnings		3,817			3,332
Less treasury stock, at cost — 53,767,753 and 41,866,451 shares, respectively		(1,503	)		(1,163	)
Accumulated other comprehensive income		571			416
Noncontrolling interest		17			12

Total Stockholders’ Equity		8,221			7,697

Total Liabilities and Stockholders’ Equity	$	27,419		$	23,378

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,	2010			2009

Cash Flows from Operating Activities
Net income	$	491		$	908
Adjustments to reconcile net income to net cash provided by operating activities:
Distributions and equity in earnings of unconsolidated affiliates		(19	)		(33	)
Depreciation and amortization		620			594
Provision for bad debts		46			37
Amortization of nuclear fuel		30			28
Amortization of financing costs and debt discount/premiums		23			35
Amortization of intangibles and out-of-market contracts		(17	)		79
Changes in deferred income taxes and liability for uncertain tax benefits		272			561
Changes in nuclear decommissioning trust liability		26			19
Changes in derivatives		(48	)		(234	)
Changes in collateral deposits supporting energy risk management activities		(116	)		13
(Gain)/loss on sale and disposal of assets, net		(6	)		2
Gain on sale of equity method investment		—			(128	)
Loss/(gain) on sale of emission allowances		4			(8	)
Gain recognized on settlement of pre-existing relationship		—			(31	)
Amortization of unearned equity compensation		23			20
Changes in option premiums collected, net of acquisition		60			(278	)
Cash used by changes in other working capital, net of acquisition		(248	)		(304	)

Net Cash Provided by Operating Activities		1,141			1,280

Cash Flows from Investing Activities
Acquisition of businesses, net of cash acquired		(142	)		(356	)
Capital expenditures		(490	)		(560	)
Increase in restricted cash, net		(17	)		(10	)
Decrease/(increase) in notes receivable		28			(18	)
Purchases of emission allowances		(56	)		(68	)
Proceeds from sale of emission allowances		14			20
Investments in nuclear decommissioning trust fund securities		(245	)		(237	)
Proceeds from sales of nuclear decommissioning trust fund securities		219			218
Proceeds from renewable energy grants		102			—
Proceeds from sale of assets, net		30			6
Proceeds from sale of equity method investment		—			284
Other		(13	)		(6	)

Net Cash Used by Investing Activities		(570	)		(727	)

Cash Flows from Financing Activities
Payment of dividends to preferred stockholders		(7	)		(27	)
Payment for treasury stock		(180	)		(250	)
Net receipt from/(payments for) acquired derivatives that include financing elements		58			(140	)
Installment proceeds from sale of noncontrolling interest in subsidiary		50			50
Proceeds from issuance of long-term debt		1,252			843
Proceeds from issuance of term loan for funded letter of credit facility		1,300			—
Increase in restricted cash supporting funded letter of credit facility		(1,301	)		—
Proceeds from issuance of common stock		2			1
Payment of deferred debt issuance costs		(70	)		(29	)
Payments for short and long-term debt		(529	)		(248	)

Net Cash Provided by Financing Activities		575			200

Effect of exchange rate changes on cash and cash equivalents		(3	)		3

Net Increase in Cash and Cash Equivalents		1,143			756
Cash and Cash Equivalents at Beginning of Period		2,304			1,494

Cash and Cash Equivalents at End of Period	$	3,447		$	2,250

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 U.S., as well as a major retail electricity provider in the ERCOT (Texas) market. NRG is engaged in the ownership, development, construction and operation of power generation facilities, both conventional and renewable, the transacting in and trading of fuel and transportation services, the trading of energy, capacity and related products in the U.S. 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 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, 2009, or 2009 Form 10-K. 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, 2010, the results of operations for the three and nine months ended September 30, 2010, and 2009, and cash flows for the nine months ended September 30, 2010, and 2009. Certain prior-year amounts have been reclassified for comparative purposes.

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

Other Cash Flow Information

NRG’s investing activities do not include capital expenditures of $215 million which were accrued and unpaid at September 30, 2010.

Recent Accounting Developments

ASU No. 2009-17 — On January 1, 2010, the Company adopted the provisions of ASU No. 2009-17, Consolidations: Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities, or ASU 2009-17. This guidance amends ASC 810 by altering how a company determines when an entity that is insufficiently capitalized or not controlled through its voting interests should be consolidated. The previous ASC 810 guidance required a quantitative analysis of the economic risk/rewards of a Variable Interest Entity, or a VIE, to determine the primary beneficiary. ASU 2009-17 specifies that a qualitative analysis be performed, requiring the primary beneficiary to have both the power to direct the activities of a VIE that most significantly impact the entities’ economic performance, as well as either the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE. The Company’s adoption of ASU 2009-17 on January 1, 2010, did not have an impact on its results of operations, financial position or cash flows.

ASU No. 2010-10 — In February 2010, the FASB issued ASU No. 2010-10, Consolidation (Topic 810): Amendments for Certain Investment Funds, or ASU 2010-10. The amendments to ASC 810 clarify that related parties should be considered when evaluating the criteria for determining whether a decision maker’s or service provider’s fee represents a variable interest. In addition, the amendments clarify that a quantitative calculation should not be the sole basis for evaluating whether a decision maker’s or service provider’s fee represents a variable interest. The Company adopted the provisions of ASU 2010-10 effective January 1, 2010, with no impact on its results of operations, financial position or cash flows.

Other effects of ASU 2009-17/ASU 2010-10 adoption — NRG determined that one of its equity method investments was a VIE as of January 1, 2010, upon adoption of this new guidance. NRG owns a 50% interest in Sherbino I Wind Farm LLC, or Sherbino, a 150 MW wind farm operated as a joint venture with BP Wind Energy North America Inc. The Company has determined that Sherbino is a VIE, but the Company is not the primary beneficiary, under the amended guidance in ASU 2009-17 and ASU 2010-10. Therefore, NRG will continue to account for its investment in Sherbino under the equity method. NRG’s maximum exposure to loss is limited to its equity investment, which is $100 million as of September 30, 2010.

Borrowings of an equity method investment — In December 2008, Sherbino entered into a 15-year term loan facility which is non-recourse to NRG. As of September 30, 2010, the outstanding principal balance of the term loan facility was $131 million, and is secured by substantially all of Sherbino’s assets and membership interests.

ASU No. 2010-09 — In February 2010, the FASB issued ASU No. 2010-09, Subsequent Events (Topic 855): Amendments to Certain Recognition and Disclosure Requirements, or ASU 2010-09. Under the amendments of ASU 2010-09, an entity that is an SEC filer is not required to disclose the date through which subsequent events have been evaluated. As this guidance provides only disclosure requirements, the adoption of ASU 2010-09 effective January 1, 2010, did not impact the Company’s results of operations, financial position or cash flows.

Other — The following accounting standards were adopted on January 1, 2010, with no impact on the Company’s results of operations, financial position or cash flows:

•

ASU No. 2009-15, Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing, or ASU 2009-15.

•

ASU No. 2010-02, Consolidation (Topic 810): Accounting and Reporting for Decreases in Ownership of a Subsidiary — a Scope Clarification, or ASU 2010-02.

•

ASU No. 2010-06, Fair Value Measurement and Disclosures: Improving Disclosures about Fair Value Measurements, or ASU 2010-06.

Note 3 — Comprehensive Income

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)	2010		2009			2010			2009

Net income	$	223	$	278		$	491		$	908

Changes in derivative activity		59		(73	)		162			(9	)
Foreign currency translation adjustment		36		20			(6	)		38
Reclassification adjustment for translation gain realized upon sale of foreign investments		—		—			—			(22	)
Unrealized gain/(loss) on available-for-sale securities		—		1			(1	)		3

Other comprehensive income/(loss)		95		(52	)		155			10

Less: Comprehensive loss attributable to noncontrolling interest		—		—			(1	)		(1	)

Comprehensive income attributable to NRG Energy, Inc.	$	318	$	226		$	647		$	919

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, 2009	$	416
Changes in derivative activity		162
Foreign currency translation adjustment		(6	)
Unrealized loss on available-for-sale securities		(1	)

Accumulated other comprehensive income as of September 30, 2010	$	571

Note 4 — Business Acquisitions and Dispositions

Acquisitions Closed or Announced in 2010

The following acquisitions were announced during the third quarter of 2010:

Green Mountain — On September 16, 2010, NRG agreed to acquire Green Mountain Energy Company, or Green Mountain, for $350 million in cash. Austin-based Green Mountain, a leading retail provider of clean energy products and services, has residential and commercial customers primarily in Texas, Oregon, and the New York metro region. Green Mountain also delivers renewable products and services to select utilities that are better for the environment, as well as providers in New York and New Jersey. Green Mountain, which will be managed and operated as a distinct retail business within NRG, offers cleaner electricity products from renewable sources and a variety of carbon offset products. NRG anticipates funding the transaction with cash on hand. The transaction, which is expected to close in November 2010, has received the required regulatory approvals, but remains subject to customary closing conditions.

Dynegy Plants — On August 13, 2010, NRG signed a definitive agreement with an affiliate of The Blackstone Group L.P., or Blackstone, to purchase 3,884 MW of Dynegy Inc., or Dynegy, assets in California and Maine for $1.36 billion in cash. The Dynegy plants in California consist of 1,020 MW of combined cycle, 2,159 MW of steam turbine, and 165 MW of combustion turbine generating capacity, each gas-fired with the exception of an oil-fired combustion turbine. The Maine plant is a 540 MW gas-fired combined cycle facility. Out of the total California capacity to be acquired, 2,159 MW are under tolling agreements with 165 MW under an RMR agreement. The Maine plant dispatches into ISO-NE where it earns capacity revenues. The Company anticipates funding the acquisition with cash on hand. The acquisition is subject to the satisfaction of closing conditions, including the completion of Blackstone’s acquisition of Dynegy in a separately announced merger (which, itself, requires a vote by the shareholders of Dynegy), and the receipt of required government approvals. There are no assurances that the conditions to Blackstone’s acquisition of Dynegy will be satisfied or that Blackstone’s acquisition of Dynegy will be consummated on the terms agreed to, if at all.

Cottonwood — On August 12, 2010, NRG agreed to acquire the Cottonwood Generating Station, a 1,279 MW combined cycle natural gas plant in the Entergy zone of east Texas, or Cottonwood, from Kelson Limited Partnership for $525 million in cash. The Company intends to fund the Cottonwood acquisition with cash on hand. The Cottonwood acquisition is expected to close by year end, subject to customary closing conditions and regulatory approvals.

The following acquisitions closed during the second quarter of 2010:

Northwind Phoenix — On June 22, 2010, NRG, through its wholly-owned subsidiary, NRG Thermal LLC, or NRG Thermal, acquired Northwind Phoenix, LLC, or Northwind Phoenix, for a total purchase price of $100 million in cash, plus a payment for acquired working capital. Northwind Phoenix owns and operates a district cooling system that provides chilled water to commercial buildings in the Phoenix central business district. In addition, Northwind Phoenix maintains and operates Combined Heat and Power plants that provide chilled water, steam and electricity in metropolitan Tucson and to portions of Arizona State University campuses in Tempe and Mesa. The acquisition was financed by the issuance of $100 million in notes by NRG Thermal. See Note 8, Long-Term Debt to this Form 10-Q, for information related to the notes issued.

South Trent — On June 14, 2010, NRG acquired South Trent Wind LLC, owner of the South Trent wind farm, or South Trent, a 101 MW wind farm near Sweetwater, Texas, for a total purchase price of $111 million. South Trent commenced operations in January 2009 and consists of 44 turbines producing up to 2.3 MW of power each. The project has a 20-year PPA, which commenced January 2009, for all generation from the site. In connection with the acquisition, NRG paid $32 million in cash and South Trent entered into a financing arrangement that includes a $79 million term loan. See Note 8, Long-Term Debt to this Form 10-Q, for information related to this financing arrangement.

2009 Acquisition of Reliant Energy

As discussed more fully in Note 3 — Business Acquisitions, to the Company’s 2009 Form 10-K, NRG acquired Reliant Energy on May 1, 2009, for total consideration of approximately $401 million. The following measurement period adjustments to the provisional amounts recorded as of December 31, 2009, attributable to refinement of the underlying appraisal assumptions, were recognized during the first quarter of 2010, the end of the measurement period: customer relationships decreased by $6 million and current and non-current liabilities increased by $6 million, resulting in no change to net assets acquired. The accounting for this business combination was completed on March 31, 2010.

Dispositions

Padoma — On January 11, 2010, NRG sold its terrestrial wind development company, Padoma Wind Power LLC, or Padoma, to Enel North America, Inc., or Enel. NRG retained its existing ownership interest in its three Texas wind farms: Sherbino, Elbow Creek and Langford. In addition, NRG will maintain a strategic partnership with Enel to evaluate potential opportunities in renewable energy, including the opportunity to participate in wind projects currently in development. NRG recognized a gain on the sale of Padoma of $23 million, which was recorded as a component of operating income in the statement of operations.

MIBRAG — On June 10, 2009, NRG sold its 50% ownership interest in Mibrag B.V. whose principal holding was 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. For the nine months ended September 30, 2009, NRG recorded an exchange loss of $24 million on the contract within Other income/(expense), net.

Note 5 — 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,
	2010		2009		2010		2009
	(In millions)
Assets:
Cash and cash equivalents	$	3,447	$	2,304	$	3,447	$	2,304
Funds deposited by counterparties		457		177		457		177
Restricted cash		19		2		19		2
Cash collateral paid in support of energy risk management activities		477		361		477		361
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities		7		9		7		9
Marketable equity securities		4		5		4		5
Trust fund investments		391		369		391		369
Notes receivable		178		231		192		238
Derivative assets		3,480		2,319		3,480		2,319
Restricted cash supporting funded letter of credit facility		1,301		—		1,301		—
Liabilities:
Long-term debt, including current portion		9,112		8,295		9,290		8,211
Funded letter of credit		1,300		—		1,271		—
Cash collateral received in support of energy risk management activities		457		177		457		177
Derivative liabilities	$	2,572	$	1,860	$	2,572	$	1,860

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, 2010	Level 1		Level 2		Level 3		Total

Cash and cash equivalents	$	3,447	$	—	$	—	$	3,447
Funds deposited by counterparties		457		—		—		457
Restricted cash		19		—		—		19
Cash collateral paid in support of energy risk management activities		477		—		—		477
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities		—		—		7		7
Marketable equity securities		4		—		—		4
Trust fund investments
Cash and cash equivalents		12		—		—		12
U.S. government and federal agency obligations		31		—		—		31
Federal agency mortgage-backed securities		—		57		—		57
Commercial mortgage-backed securities		—		10		—		10
Corporate debt securities		—		51		—		51
Marketable equity securities		191		—		37		228
Foreign government fixed income securities		—		2		—		2
Derivative assets
Commodity contracts		1,219		2,194		59		3,472
Interest rate contracts		—		—		8		8
Restricted cash supporting funded letter of credit facility		1,301		—		—		1,301

Total assets	$	7,158	$	2,314	$	111	$	9,583


Cash collateral received in support of energy risk management activities	$	457	$	—	$	—	$	457
Derivative liabilities
Commodity contracts		1,347		993		112		2,452
Interest rate contracts		—		120		—		120

Total liabilities	$	1,804	$	1,113	$	112	$	3,029


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

Cash and cash equivalents	$	2,304	$	—	$	—	$	2,304
Funds deposited by counterparties		177		—		—		177
Restricted cash		2		—		—		2
Cash collateral paid in support of energy risk management activities		361		—		—		361
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities		—		—		9		9
Marketable equity securities		5		—		—		5
Trust fund investments		214		118		37		369
Derivative assets		489		1,767		63		2,319

Total assets	$	3,552	$	1,885	$	109	$	5,546

Cash collateral received in support of energy risk management activities	$	177	$	—	$	—	$	177
Derivative liabilities		501		1,283		76		1,860

Total liabilities	$	678	$	1,283	$	76	$	2,037

There have been no transfers during the three months and nine months ended September 30, 2010, between Levels 1 and 2. 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:


	Three months ended September 30, 2010											Nine months ended September 30, 2010
	Debt			Trust Fund								Debt			Trust Fund
(In millions)	Securities			Investments		Derivatives^(a)			Total			Securities			Investments		Derivatives^(a)			Total

Beginning Balance	$	10		$	32	$	(76	)	$	(34	)	$	9		$	37	$	(13	)	$	33
Total gains/(losses) (realized and unrealized)
Included in earnings		3			—		18			21			3			—		(13	)		(10	)
Included in OCI		(1	)		—		—			(1	)		—			—		—			—
Included in nuclear decommissioning obligations		—			5		—			5			—			—		—			—
Purchases		—			—		(10	)		(10	)		—			—		(1	)		(1	)
Sales		(5	)		—		—			(5	)		(5	)		—		—			(5	)
Transfer into Level 3 ^(b)		—			—		31			31			—			—		(16	)		(16	)
Transfer out of Level 3 ^(b)		—			—		(8	)		(8	)		—			—		(2	)		(2	)

Ending balance as of September 30, 2010	$	7		$	37	$	(45	)	$	(1	)	$	7		$	37	$	(45	)	$	(1	)

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, 2010	$	—		$	—	$	12		$	12		$	—		$	—	$	(24	)	$	(24	)


	Three months ended September 30, 2009											Nine months ended September 30, 2009
	Debt			Trust Fund								Debt			Trust Fund
(In millions)	Securities			Investments		Derivatives^(a)			Total			Securities			Investments		Derivatives^(a)			Total

Beginning Balance	$	7		$	34	$	50		$	91		$	7		$	31	$	49		$	87
Total gains/(losses) (realized and unrealized)
Included in earnings		—			—		(80	)		(80	)		—			—		(110	)		(110	)
Included in OCI		1			—		—			1			1			—		—			1
Included in nuclear decommissioning obligations		—			6		—			6			—			8		—			8
Purchases/(sales), net		—			—		1			1			—			1		(3	)		(2	)
Transfer in/(out) of Level 3 ^(b)		—			—		(41	)		(41	)		—			—		(6	)		(6	)

Ending balance as of September 30, 2009	$	8		$	40	$	(70	)	$	(22	)	$	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	$	—		$	—	$	(25	)	$	(25	)	$	—		$	—	$	3		$	3


(a)	Consists of derivative assets and liabilities, net.

(b)	Transfers in/(out) of Level 3 are related to the availability of external broker quotes, and are valued as of the end of the reporting period. All transfers in/(out) are with Level 2.

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, 2010, the credit reserve resulted in a $6 million decrease in fair value which is composed of a $3 million loss in OCI and a $3 million loss in operating revenue and cost of operations.

Concentration of Credit Risk

In addition to the credit risk discussion as disclosed in Note 2, Summary of Significant Accounting Policies, to the Company’s 2009 Form 10-K, the following item is a discussion of the concentration of credit risk for the Company’s financial instruments. 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. NRG is exposed to counterparty credit risk through various activities including wholesale sales, fuel purchases and retail supply and retail customer credit risk through its retail load activities.

Counterparty Credit Risk

The Company monitors and manages counterparty 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, prepayment arrangements, or volumetric limits; (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 credit risk with a diversified portfolio of counterparties. 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.

As of September 30, 2010, counterparty credit exposure to a significant portion of the Company’s counterparties was $1.7 billion and NRG held collateral (cash and letters of credit) against those positions of $461 million, resulting in a net exposure of $1.2 billion. Counterparty credit exposure is discounted at the risk free rate. The following table highlights the counterparty credit quality and the net counterparty credit exposure by industry sector. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market and Normal Purchase Normal Sale, or NPNS, and non-derivative transactions. The exposure is shown net of collateral held, and includes amounts net of receivables or payables.


	Net Exposure ^(b)
Category	(% of Total)

Financial institutions		63	%
Utilities, energy, merchants, marketers and other		27
Coal suppliers		6
ISOs		4

Total as of September 30, 2010		100	%


	Net Exposure ^(b)
Category	(% of Total)

Investment grade		75	%
Non-Investment grade		6
Non-rated ^(a)		19

Total as of September 30, 2010		100	%


(a)	For non-rated counterparties, the majority are related to ISO and municipal public power entities, which are considered investment grade equivalent ratings based on NRG’s internal credit ratings.

(b)	Counterparty credit exposure excludes uranium and coal transportation contracts from counterparty credit exposure because of the illiquidity of the reference markets.

NRG has counterparty credit risk exposure to certain counterparties representing more than 10% of the total net exposure discussed above and the aggregate of such counterparties was $435 million. Approximately 79% of NRG’s positions relating to this credit risk roll-off by the end of 2012. 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 or results of operations from nonperformance by any of NRG’s counterparties.

Counterparty credit exposure described above excludes credit risk exposure under California tolling agreements, Northeast and South Central load obligations and a coal supply agreement, which are generally long-term. As external sources or observable market quotes are not available to estimate such exposure, the Company valued these contracts based on various 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. Based on these valuation techniques, as of September 30, 2010, credit risk exposure to these counterparties is approximately $550 million. Many of these power contracts are with utilities or public power entities that have strong credit quality and specific public utility commission or other regulatory support. In the case of the coal supply agreement, NRG holds a lien against the underlying asset. These factors significantly reduce the risk of loss.

Retail Customer Credit Risk

NRG is exposed to retail credit risk through the Company’s 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 may result from both nonpayment of customer accounts receivable and the loss of 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 arrangements.

As of September 30, 2010, the Company’s retail customer credit exposure to C&I customers was diversified across many customers and various industries, with a significant portion of the exposure with government entities.

NRG is also exposed to retail customer credit risk relating to its Mass customers, which results in a write-off of bad debt. During 2010, the Company continued to experience improved customer payment behavior, but current economic conditions may affect the ability of the Company’s customers to pay bills in a timely manner, which could increase customer delinquencies and may lead to an increase in bad debt expense.

This footnote should be read in conjunction with the complete description under Note 5, Fair Value of Financial Instruments, to the Company’s 2009 Form 10-K.

Note 6 — Nuclear Decommissioning Trust Fund

NRG’s nuclear decommissioning trust fund assets, which are for its portion of the decommissioning of the South Texas Project, or STP, are comprised of securities classified as available-for-sale and recorded at fair value based on actively quoted market prices. NRG accounts for the nuclear decommissioning trust fund in accordance with ASC-980 — Regulated Operations, or ASC 980. Since the Company is in compliance with the Public Utility Commission of Texas, or PUCT, rules and regulations regarding decommissioning trusts and the cost of decommissioning is the responsibility of the Texas ratepayers, not NRG, all realized and unrealized gains or losses (including other than-temporary-impairments) related to the Nuclear Decommissioning Trust Fund are recorded to the Nuclear Decommissioning Trust Liability to the ratepayers and are not included in net income or accumulated other comprehensive income, consistent with regulatory treatment.

The following table summarizes the aggregate fair values and unrealized gains and losses (including other-than-temporary impairments) for the securities held in the trust funds as of September 30, 2010, and December 31, 2009, as well as information about the contractual maturities of those securities. The cost of securities sold is determined on the specific identification method.


	As of September 30, 2010								As of December 31, 2009
							Weighted-								Weighted-
							average								average
	Fair		Unrealized		Unrealized		maturities		Fair		Unrealized		Unrealized		maturities
(In millions, except otherwise noted)	Value		gains		losses		(in years)		Value		gains		losses		(in years)

Cash and cash equivalents	$	12	$	—	$	—		—	$	4	$	—	$	—		—
U.S. government and federal agency obligations		29		2		—		10		23		1		—		8
Federal agency mortgage-backed securities		57		2		—		22		60		2		—		23
Commercial mortgage-backed securities		10		—		—		29		10		—		1		29
Corporate debt securities		51		4		1		10		48		3		1		10
Marketable equity securities		228		95		1		—		220		89		2		—
Foreign government fixed income securities		2		—		—		7		2		—		—		6

Total	$	389	$	103	$	2			$	367	$	95	$	4

The following tables summarize proceeds from sales of available-for-sale securities and the related realized gains and losses from these sales:


	Nine months ended September 30,
(In millions)	2010		2009

Realized gains	$	4	$	2
Realized losses		2		2
Proceeds from sale of securities		219		218

Note 7 — Accounting for Derivative Instruments and Hedging Activities

This footnote should be read in conjunction with the complete description under Note 6, Accounting for Derivative Instruments and Hedging Activities, to the Company’s 2009 Form 10-K.

Energy-Related Commodities

As of September 30, 2010, NRG had cash flow hedge energy-related derivative financial instruments extending through December 2013.

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, 2010, NRG had interest rate derivative instruments extending through June 2028, the majority 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 open derivative transactions broken out by commodity, excluding those derivatives that qualified for the NPNS exception as of September 30, 2010, and December 31, 2009. Option contracts are reflected using delta volume. Delta volume equals the notional volume of an option adjusted for the probability that the option will be in-the-money at its expiration date.


		Total Volume
		September 30, 2010			December 31, 2009
Commodity	Units	(In millions)

Emissions	Short Ton		(7	)		(2	)
Coal	Short Ton		39			55
Natural Gas	MMBtu		(189	)		(484	)
Oil	Barrel		—			1
Power	MWh		1			5
Capacity	MW/Day		(1	)		(2	)
Interest	Dollars	$	3,203		$	3,291

Fair Value of Derivative Instruments

The following table summarizes the fair value within the derivative instrument valuation on the balance sheet:


	Fair Value
	Derivative Assets				Derivative Liabilities
	September 30,		December 31,		September 30,		December 31,
(In millions)	2010		2009		2010		2009

Derivatives Designated as Cash Flow or Fair Value Hedges:
Interest rate contracts current	$	—	$	—	$	34	$	2
Interest rate contracts long-term		8		8		85		106
Commodity contracts current		478		300		2		12
Commodity contracts long-term		562		508		—		6

Total Derivatives Designated as Cash Flow or Fair Value Hedges		1,048		816		121		126

Derivatives Not Designated as Cash Flow or Fair Value Hedges:
Commodity contracts current		2,001		1,336		2,036		1,459
Commodity contracts long-term		431		167		414		275
Interest rate contracts long-term		—		—		1		—

Total Derivatives Not Designated as Cash Flow or Fair Value Hedges		2,432		1,503		2,451		1,734

Total Derivatives	$	3,480	$	2,319	$	2,572	$	1,860

Accumulated Other Comprehensive Income

The following table summarizes the effects of ASC 815 on NRG’s Accumulated OCI balance attributable to cash flow hedge derivatives, net of tax:


	Three months ended September 30, 2010									Nine months ended September 30, 2010
	Energy			Interest						Energy			Interest
(In millions)	Commodities			Rate			Total			Commodities			Rate			Total

Beginning balance	$	575		$	(66	)	$	509		$	461		$	(55	)	$	406
Reclassified from Accumulated OCI to income:
- Due to realization of previously deferred amounts		(110	)		—			(110	)		(344	)		—			(344	)
Mark-to-market of cash flow hedge accounting contracts		173			(4	)		169			521			(15	)		506

Accumulated OCI balance at September 30, 2010, net of $342 tax	$	638		$	(70	)	$	568		$	638		$	(70	)	$	568

Gains/(losses) expected to be realized from Accumulated OCI during the next 12 months, net of $224 tax	$	407		$	(24	)	$	383		$	407		$	(24	)	$	383

Gains recognized in income from the ineffective portion of cash flow hedges	$	14		$	—		$	14		$	—		$	2		$	2


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

Beginning balance	$	445		$	(66	)	$	379		$	406		$	(91	)	$	315
Reclassified from Accumulated OCI to income:
- Due to realization of previously deferred amounts		(75	)		—			(75	)		(263	)		—			(263	)
- Due to discontinuation of cash flow hedge accounting		—			—			—			(135	)		—			(135	)
Mark-to-market of cash flow hedge accounting contracts		4			(2	)		2			366			23			389

Accumulated OCI balance at September 30, 2009, net of $189 tax	$	374		$	(68	)	$	306		$	374		$	(68	)	$	306

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

Gains recognized in income from the ineffective portion of cash flow hedges	$	16		$	4		$	20		$	17		$	4		$	21

Amounts reclassified from Accumulated OCI into income and amounts recognized in income from the ineffective portion of cash flow hedges are recorded to operating revenue for commodity contracts and interest expense for interest rate contracts.

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


	Three months ended September 30,						Nine months ended September 30,
(In millions)	2010			2009			2010	2009

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

Impact of Derivative Instruments on the 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)	2010			2009			2010			2009

Unrealized mark-to-market results
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(25	)	$	1		$	(116	)	$	(33	)
Reversal of loss positions acquired as part of the Reliant Energy acquisition as of May 1, 2009		7			238			157			448
Reversal of previously recognized unrealized losses/(gains) on settled positions related to trading activity		20			(21	)		46			(125	)
Net unrealized (losses)/gains on open positions related to economic hedges		(60	)		(240	)		(129	)		70
Gains on ineffectiveness associated with open positions treated as cash flow hedges		14			16			—			17
Net unrealized gains/(losses) on open positions related to trading activity		9			(9	)		32			(1	)

Total unrealized mark-to-market results	$	(35	)	$	(15	)	$	(10	)	$	376


	Three months ended September 30,						Nine months ended September 30,
(In millions)	2010			2009			2010			2009

Revenue from operations — energy commodities	$	27		$	(217	)	$	13		$	(100	)
Cost of operations		(62	)		202			(23	)		476

Total impact to statement of operations	$	(35	)	$	(15	)	$	(10	)	$	376

Reliant Energy’s loss positions were acquired as of May 1, 2009, and valued using forward prices on that date. The 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, 2010, the $129 million loss from economic hedge positions is the result of a decrease in value of forward purchases and sales of natural gas, electricity and fuel due to a decrease in forward power and gas prices.

For the nine months ended September 30, 2009, the $70 million gain from economic hedge positions includes a $217 million gain recognized in earnings from previously deferred amounts in Accumulated OCI as the Company discontinued cash flow hedge accounting for certain 2009 transactions in Texas and New York due to lower expected generation, a $29 million loss from discontinued normal purchase and sales for coal purchases and a $118 million loss in value of forward purchases and sales of electricity and fuel due to a decrease in forward power and gas prices.

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, or require the Company to post additional collateral if there was a one notch downgrade in the Company’s credit rating. The collateral required for contracts that have adequate assurance clauses that are in a net liability position as of September 30, 2010, was $51 million. The collateral required for contracts with credit rating contingent features was $55 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 $16 million as of September 30, 2010.

See Note 5, Fair Value of Financial Instruments, to this Form 10-Q for discussion regarding concentration of credit risk.

Note 8 — Long-Term Debt

Senior Credit Facility

Prepayment

In March 2010, NRG made a repayment of approximately $229 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 2009. The Company is contemplating making a prepayment on the 2011 mandatory offer related to 2010 in the fourth quarter of 2010.

Amendment and Extension of Maturity Dates

On June 30, 2010, NRG completed an amendment and extension of the Senior Credit Facility, resulting in the following:

•

NRG extended the maturity date for approximately $1.0 billion of its $2.0 billion outstanding Term Loan Facility to August 31, 2015, with the remaining amount due on the original maturity date of February 1, 2013. The interest rate for the extended portion of the facility increased from LIBOR+1.75% to LIBOR+3.25%;

•

Borrowing capacity under the Revolving Credit Facility was reduced from $1.0 billion to $875 million and its maturity was extended to August 31, 2015. The interest rate for the amended Revolving Credit Facility is LIBOR+3.25%;

•

The existing Synthetic Letter of Credit Facility was converted into a term loan-backed funded letter of credit facility, or Funded Letter of Credit Facility, with the term loan reflected as a non-current liability and the proceeds of the term loan reflected as non-current restricted cash on NRG’s balance sheet. Of the total $1.3 billion borrowed under the term loan, $500 million will mature on February 1, 2013 and bear interest at LIBOR+1.75%, while $800 million will mature August 31, 2015, and bear interest at LIBOR+3.25%.

Restricted cash supporting funded letter of credit — Pursuant to the letter of credit reimbursement agreements entered into as of September 30, 2010, or the LC Agreements, and the Senior Credit Facility, as amended, NRG made capital contributions to NRG LC Facility Company, or LCFC, a separate, bankruptcy-remote entity that is a wholly-owned subsidiary of NRG. In addition, pursuant to reimbursement agreements related to the LC Agreements, NRG or its subsidiaries is liable for certain reimbursement obligations to LCFC. As of September 30, 2010, LCFC has cash invested in short-term certificates of deposit with an aggregate market value of $1.3 billion. Pursuant to the LC Agreements, which have a maximum committed amount of $1.3 billion, LCFC is liable on various letters of credit issued by Deutsche Bank AG, New York Branch and Citibank, N.A. These letters of credit will be used to support the businesses of NRG and certain of its other subsidiaries and equity investments. LCFC has secured its reimbursement and other obligations under the LC Agreements with a pledge of the cash and cash equivalents that it owns. The LC Agreements require LCFC’s assets to be used first and foremost to satisfy claims of creditors of LCFC. Although the cash and cash equivalents held by LCFC are included in the consolidated assets of NRG, such cash and cash equivalents are not available to creditors of NRG.

•

Expenses of approximately $46 million, including fees to the lenders and other fees, were deferred and will be expensed in part over the original term of maturity through 2013 and in part over the amended maturity through 2015.

As of September 30, 2010, NRG had issued $850 million of letters of credit under the Funded Letter of Credit Facility, leaving $450 million available for future issuances. Under the Revolving Credit Facility as of September 30, 2010, NRG had issued a letter of credit of $36 million, leaving $839 million available.

Issuance of 2020 Senior Notes

On August 20, 2010, NRG issued $1.1 billion aggregate principal amount at par of 8.25% Senior Notes due 2020, or 2020 Senior Notes. The 2020 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 12 — Debt and Capital Leases, in the Company’s 2009 Form 10-K. The Indentures and the form of the notes provide, among other things, that the 2020 Senior Notes will be senior unsecured obligations of NRG.

The net proceeds of $1.086 billion are intended to be used for general corporate purposes, including, without limitation, working capital needs, investment in business initiatives and capital expenditures, and potentially to prepay or repurchase outstanding indebtedness of NRG and/or its subsidiaries or to fund recently announced acquisitions. Interest is payable semi-annually beginning on March 1, 2011, until their maturity date of September 1, 2020. As of September 30, 2010, $1.1 billion in principal was outstanding under the 2020 Senior Notes.

Prior to September 1, 2013, NRG may redeem up to 35% of the aggregate principal amount of the 2020 Senior Notes with the net proceeds of certain equity offerings, at a redemption price of 108.25% of the principal amount. Prior to September 1, 2015, NRG may redeem all or a portion of the 2020 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 104.125% of the note, plus interest payments due on the note from the date of redemption through September 1, 2015, discounted at a Treasury rate plus 0.50%. In addition, on or after September 1, 2015, 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

On or after September 1, 2015		104.125	%
On or after September 1, 2016		102.750	%
On or after September 1, 2017		101.375	%
On or after September 1, 2018		100.000	%

Indian River Power LLC Tax-Exempt Bonds

On October 12, 2010, NRG executed a $190 million tax-exempt bond financing, or the Indian River bonds, through its wholly-owned subsidiary, Indian River Power LLC. The bonds were issued by the Delaware Economic Development Authority and will be used for construction of emission control equipment on the Indian River Generating Station in Millsboro, DE. The bonds were issued at a rate of 5.375%, have a maturity date of October 1, 2045, and are supported by an NRG guarantee. The proceeds received on October 12, 2010, were $66 million, and the remaining balance will be received over time as construction costs are paid.

Dunkirk Power LLC Tax-Exempt Bonds

On February 1, 2010, the Company fixed the rate on the Dunkirk bonds originally issued in April 2009, at 5.875%. In addition, the $59 million letter of credit issued by NRG in support of the bonds was cancelled and replaced with an NRG guarantee.

Debt Related to Capital Allocation Program

On March 3, 2010, the Company completed the early unwinding of the CSF I Debt by remitting a cash payment to Credit Suisse, or CS, of $242 million to settle the outstanding principal and interest, as compared to $249 million that would have been due at maturity in June 2010. As part of the unwind, CS returned to NRG 6,600,000 shares of NRG common stock borrowed under the Share Lending Agreement, or SLA, between the parties and released all 12,441,973 shares of NRG common stock held as collateral for the CSF I Debt. The 6,600,000 shares of NRG common stock were returned to treasury stock and will no longer be treated as outstanding for corporate law purposes. The Company has now settled all obligations related to the CSF I and II Debt entered into in 2006, as amended from time to time, as well as the SLA entered into in February 2009.

Blythe Credit Agreement

On June 24, 2010, NRG Solar Blythe LLC, or Blythe, entered into a credit agreement with a bank, or the Blythe Credit Agreement, for a $30 million term loan which has an interest rate of LIBOR plus an applicable margin which escalates 0.25% every three years and ranges from 2.5% at closing to 3.75% in year fifteen. The term loan matures in June 2028, amortizes based upon a predetermined schedule, and is secured by all of the assets of Blythe. The bank has also issued two letters of credit on behalf of Blythe totaling approximately $6.4 million. Blythe pays an availability fee of 100% of the applicable margin on these issued letters of credit.

Also related to the Blythe Credit Agreement, on June 25, 2010, Blythe entered into a fixed for floating interest rate swap for 75% of the outstanding term loan amount, intended to hedge the risks associated with floating interest rates. Blythe will pay its counterparty the equivalent of a 3.563% fixed interest payment on a predetermined notional value, and Blythe will receive quarterly the equivalent of a floating interest payment based on a three month LIBOR calculated on the same notional value. All interest rate swap payments by Blythe and its counterparty are made quarterly and the LIBOR is determined in advance of each interest period. The notional amount of the swap, which matures on June 25, 2028, is $22 million and amortizes in proportion to the loan.

South Trent Financing Agreement

On June 14, 2010, NRG completed the acquisition of South Trent, as discussed in Note 4, Business Acquisitions and Dispositions to this Form 10-Q. As part of the purchase price consideration, South Trent entered into the Amended and Restated Financing Agreement, or Financing Agreement, with a group of lenders, which matures on June 14, 2020. The Financing Agreement includes a $79 million term loan, as well as a $10 million letter of credit facility in support of the PPA, for which the full amount had been issued as of September 30, 2010. The Financing Agreement also provides for up to $8 million in additional letter of credit facilities, none of which are utilized as of September 30, 2010. The term loan accrues interest at LIBOR plus a margin based upon a grid, which is initially 2.50% and increases every two years by 12.5 basis points. The term loan amortizes quarterly based upon a predetermined schedule with the unamortized portion due at maturity.

Under the terms of the Financing Agreement, South Trent was required to enter into interest rate protection agreements that would fix the interest rate for a minimum of 75% of the outstanding principal amount. Accordingly, on June 14, 2010, South Trent entered into five interest rate swaps, intended to hedge the risks associated with floating interest rates. For each of the interest rate swaps, South Trent will pay its counterparty the equivalent of a 3.265% fixed interest payment on a predetermined notional value, and South Trent will receive the quarterly equivalent of a floating interest payment based on a three month LIBOR calculated on the same notional value. All interest rate swap payments by South Trent and its counterparties are made quarterly and the LIBOR is determined in advance of each interest period. The total notional amount of these swaps, which mature on June 14, 2020, is $59 million. The swaps amortize in proportion to the loan.

South Trent also entered into a series of forward-starting interest rate swaps that will become effective June 14, 2020, and are effective for eight years. The swaps are intended to hedge the risks associated with floating interest rates. For each of the interest rate swaps, South Trent will pay its counterparty the equivalent of a 4.95% fixed interest payment on a predetermined notional value, and receive the quarterly equivalent of a floating interest payment based on a three month LIBOR calculated on the same notional value. All interest rate swap payments by South Trent and its counterparties will be made quarterly and the LIBOR is determined in advance of each interest period. The total notional amount of these swaps, which will mature on June 14, 2028, is $21 million.

NRG Thermal Financing

On June 22, 2010, NRG Thermal’s largest subsidiary, NRG Energy Center Minneapolis LLC, or NRG Thermal Minneapolis, issued $100 million of 5.95% Series C notes due June 23, 2025, or the Series C Notes. The Series C Notes are secured by substantially all of the assets of NRG Energy Center Minneapolis. NRG Thermal has guaranteed the indebtedness and its guarantee is secured by a pledge of the equity interest in all of NRG Thermal’s subsidiaries. At the same time, NRG Thermal amended agreements for its other outstanding notes to conform to the covenants of the Series C Notes. The proceeds of the loan were used to finance the acquisition of Northwind Phoenix, as discussed in Note 4, Business Acquisitions and Dispositions to this Form 10-Q.

GenConn Energy LLC Related Financings

NRG Connecticut Peaking Development LLC, or NRG Connecticut Peaking, made funding requests under the equity bridge loan, or EBL, during the quarter. The EBL is backed by a letter of credit issued by NRG under its Funded Letter of Credit Facility equal to at least 104% of the amount outstanding. On September 29, 2010, the Devon project reached its commercial operations date, or COD, in accordance with the financing documents. Accordingly, NRG Connecticut Peaking repaid the $55 million portion of the EBL used to fund the Devon project, and converted $56 million of a promissory note from GenConn into equity. As of September 30, 2010, $61 million was outstanding under the EBL for the Middletown project and the remaining amounts will be drawn as necessary.

Borrowings of an equity method investment — In April 2009, GenConn secured financing for 50% of the Devon and Middletown project construction costs through a seven-year term loan facility, and also entered into a five-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. GenConn began to draw under the GenConn Facility to cover costs related to the Devon project in August 2009, and the Middletown project in June 2010. As of September 30, 2010, $164 million had been drawn.

NINA Financing

As of September 30, 2010, NINA had $7 million outstanding under the TANE Facility. On June 1, 2010, NINA repaid $20 million outstanding under its revolving credit facility, and the facility was terminated.

Note 9 — Changes in Capital Structure

The following table reflects the changes in NRG’s common stock issued and outstanding:


	Authorized		Issued		Treasury			Outstanding

Balance as of December 31, 2009		500,000,000		295,861,759		(41,866,451	)		253,995,308
Shares issued under LTIP		—		440,517		—			440,517
Shares issued under NRG Employee Stock Purchase Plan, or ESPP		—		—		120,990			120,990
Capital Allocation Plan		—		—		(5,422,292	)		(5,422,292	)
Shares returned by affiliates of CS		—		—		(6,600,000	)		(6,600,000	)
4% Preferred Stock conversion		—		7,701,450		—			7,701,450

Balance as of September 30, 2010		500,000,000		304,003,726		(53,767,753	)		250,235,973

2010 Capital Allocation Plan

As part of the Company’s 2010 Capital Allocation Plan, the Company repurchased $50 million of NRG’s common stock through open market purchases in the second quarter of 2010. On August 26, 2010, the Company entered into an accelerated share repurchase agreement, or ASR Agreement, with a financial institution to repurchase a total of $130 million of NRG common stock, based on a volume weighted average price less a specified discount. On August 27, 2010, under the ASR Agreement, the Company remitted $130 million to the financial institution, and received 3,208,292 shares of NRG common stock with a fair value of $65 million, with the remaining shares to be delivered at settlement. The ASR Agreement was accounted for as two separate transactions: a $65 million purchase of NRG common stock at cost; and a $65 million forward contract indexed to the Company’s own stock. Both transactions were recorded as treasury stock on August 27, 2010. The ASR Agreement settled on October 22, 2010, and the Company received an additional 3,040,919 shares of NRG common stock. The shares repurchased under the ASR Agreement complete the Company’s previously announced $180 million share buyback program for 2010.

Share Lending Agreements

As part of the CSF I Debt unwind on March 3, 2010, CS returned to NRG 6,600,000 shares of NRG common stock borrowed under the SLA between the parties. The 6,600,000 shares of NRG common stock were returned to treasury stock and will no longer be treated as outstanding for corporate law purposes. See Note 8, Long-Term Debt, to this Form 10-Q for more information.

4% Preferred Stock

As of January 21, 2010, the Company completed the redemption of all remaining outstanding shares of 4% Preferred Stock, with holders converting 154,029 Preferred Stock shares into 7,701,450 shares of common stock and the Company redeeming 28 Preferred Stock shares for $28 thousand in cash.

Note 10 — Equity Compensation

Non-Qualified Stock Options, or NQSOs

The following table summarizes the Company’s NQSO activity, and changes during the nine months then ended:


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

Outstanding as of December 31, 2009		4,793,585		$	25.07
Granted		754,200			23.79
Exercised		(111,331	)		22.12
Forfeited		(367,702	)		29.97

Outstanding at September 30, 2010		5,068,752			24.59	$	10
Exercisable at September 30, 2010		3,355,564		$	23.70	$	10

The weighted average grant date fair value of NQSOs granted for the nine months ended September 30, 2010, was $10.67.

Restricted Stock Units, or RSUs

The following table summarizes the Company’s non-vested RSU awards, and changes during the nine months then ended:


				Weighted Average
				Grant-Date
	Units			Fair Value Per Unit

Non-vested as of December 31, 2009		1,614,769		$	30.78
Granted		352,600			23.66
Vested		(469,650	)		37.00
Forfeited		(133,350	)		29.65

Non-vested as of September 30, 2010		1,364,369		$	26.90

Performance Units, or PUs

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


				Weighted Average
				Grant-Date
	Units			Fair Value Per Unit

Non-vested as of December 31, 2009		617,300		$	24.27
Granted		348,500			23.81
Forfeited		(209,800	)		23.02

Non-vested as of September 30, 2010		756,000		$	24.40

In the nine months ended September 30, 2010, there were no performance unit payouts in accordance with the terms of the performance units.

Deferral Stock Units, or DSUs

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


				Weighted Average
				Grant-Date
	Units			Fair Value Per Unit

Outstanding as of December 31, 2009		304,049		$	19.34
Granted		59,067			22.18
Conversions		(28,395	)		21.77

Outstanding as of September 30, 2010		334,721		$	19.63

On July 29, 2010, the Company’s stockholders approved the Amended and Restated Long Term Incentive Plan, which included an increase in the shares authorized for issuance under the plan from 16 million shares to 22 million shares.

Note 11 — Earnings Per Share

Basic earnings per share attributable to NRG common stockholders is computed by dividing net income attributable to NRG Energy Inc. adjusted for accumulated preferred stock dividends by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the year are weighted for the portion of the year that they were outstanding.

Diluted earnings per share 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.

On March 3, 2010, as part of the CSF I Debt unwind, CS returned 6,600,000 shares of NRG common stock borrowed under the SLA between the parties. These shares had not been treated as outstanding for earnings per share purposes because CS was required to return all borrowed shares (or identical shares) upon termination of the SLA. See Note 8, Long-Term Debt, to this Form 10-Q, for more information on the SLA.

The reconciliation of basic earnings per 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)	2010			2009			2010			2009

*Basic earnings per share attributable to NRG common stockholders*
Numerator:
Net income attributable to NRG Energy, Inc.	$	223		$	278		$	492		$	909
Preferred stock dividends		(2	)		(6	)		(7	)		(27	)

Net income attributable to NRG Energy, Inc. available to common stockholders	$	221		$	272		$	485		$	882

Denominator:
Weighted average number of common shares outstanding		252			249			254			247
*Basic earnings per share:*
Net income attributable to NRG Energy, Inc.	$	0.88		$	1.09		$	1.91		$	3.58

*Diluted earnings per share attributable to NRG common stockholders*
Numerator:
Net income available to common stockholders	$	221		$	272		$	485		$	882
Add preferred stock dividends for dilutive preferred stock		—			4			—			19

Net income attributable to NRG Energy, Inc. available to common stockholders	$	221		$	276		$	485		$	901

Denominator:
Weighted average number of common shares outstanding		252			249			254			247
Incremental shares attributable to the issuance of equity compensation (treasury stock method)		1			2			1			1
Incremental shares attributable to assumed conversion features of outstanding preferred stock (if-converted method)		—			21			—			26

Total dilutive shares		253			272			255			274
*Diluted earnings per share:*

Net income attributable to NRG Energy, Inc.	$	0.87		$	1.02		$	1.90		$	3.29

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:


	Three months ended				Nine months ended
	September 30,				September 30,
(In millions of shares)	2010		2009		2010		2009

Equity compensation — NQSOs and PUs		6		5		6		6
Embedded derivative of 3.625% redeemable perpetual preferred stock		16		16		16		16
Embedded derivative of CSF II Debt		—		7		—		8

Total		22		28		22		30

Note 12 — Segment Reporting

NRG’s segment structure reflects the Company’s core areas of operation, which are primarily Reliant Energy, 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 millions)				Wholesale Power Generation
Three months ended	Reliant							South
September 30, 2010	Energy			Texas ^(a)		Northeast		Central		West		International		Thermal		Corporate			Elimination			Total

Operating revenues	$	1,562		$	1,040	$	353	$	166	$	43	$	30	$	40	$	(1	)	$	(548	)	$	2,685
Depreciation and amortization		32			124		29		17		2		—		3		3			—			210
Equity in earnings of unconsolidated affiliates		—			8		—		—		4		4		—		—			—			16
Income/(loss) before income taxes		(20	)		439		23		8		20		10		3		(171	)		—			312

Net income/(loss) attributable to NRG Energy, Inc.	$	(20	)	$	439	$	23	$	8	$	20	$	7	$	3	$	(257	)	$	—		$	223

Total assets	$	1,854		$	13,887	$	1,857	$	840	$	366	$	766	$	340	$	29,886		$	(22,377	)	$	27,419


(a)	Includes inter-segment sales of $547 million to Reliant Energy.


(In millions)			Wholesale Power Generation
Three months ended	Reliant						South
September 30, 2009	Energy		Texas ^(b)		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) 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


(b)	Includes inter-segment sales of $162 million to Reliant Energy.


(In millions)			Wholesale Power Generation
Nine months ended	Reliant								South
September 30, 2010	Energy		Texas ^(c)			Northeast			Central		West		International		Thermal		Corporate			Elimination			Total

Operating revenues	$	4,020	$	2,602		$	837		$	461	$	110	$	95	$	103	$	(3	)	$	(1,192	)	$	7,033
Depreciation and amortization		91		365			92			49		8		—		8		7			—			620
Equity in earnings/(losses) of unconsolidated affiliates		—		19			(1	)		—		5		19		—		(1	)		—			41
Income/(loss) before income taxes		69		971			73			8		34		51		5		(449	)		—			762
Net loss attributable to non-controlling interest		—		(1	)		—			—		—		—		—		—			—			(1	)

Net income/(loss) attributable to NRG Energy, Inc.	$	69	$	972		$	73		$	8	$	34	$	36	$	5	$	(705	)	$	—		$	492


(c)	Includes inter-segment sales of $1,187 million to Reliant Energy.


(In millions)			Wholesale Power Generation
Nine months ended	Reliant							South
September 30, 2009	Energy ^(d)		Texas ^(e)			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) before income taxes		807		681			303		(42	)		32		149		6		(414	)		—			1,522
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


(d)	Reliant Energy results are for the period May 1, 2009, to September 30, 2009.

(e)	Includes inter-segment sales of $228 million to Reliant Energy.

Note 13 — Income Taxes

Effective Tax Rate

The Company’s income tax provision consisted of the following:


	Three months ended September 30,						Nine months ended September 30,
(In millions except otherwise noted)	2010			2009			2010			2009

Income tax expense	$	89		$	166		$	271		$	614
Effective tax rate		28.5	%		37.4	%		35.6	%		40.3	%

For the three months ended September 30, 2010, NRG’s overall effective tax rate was lower than the statutory rate of 35% primarily due to the reduction in the valuation allowance resulting from the generation of capital gains during the quarter. For the three months ended September 30, 2009, NRG’s effective tax rate was higher than the statutory rate of 35% primarily due to state and local income taxes and the U.S. taxation of foreign earnings.

For the nine months ended September 30, 2010, NRG’s overall effective tax rate was higher than the statutory rate of 35% primarily due to the state and local income taxes and the U.S. taxation of foreign earnings. The rate was reduced due to the reduction in the valuation allowance resulting from the generation of overall capital gains during the year. For the nine months ended September 30, 2009, NRG’s overall effective tax rate was higher than the statutory rate of 35% primarily due to an increase in the valuation allowance as a result of capital losses generated in the nine month period for which there were no projected capital gains or available tax planning strategies.

Uncertain tax benefits

As of September 30, 2010, NRG has recorded a $557 million non-current tax liability for uncertain tax benefits, primarily resulting from taxable earnings for the period for which there are no net operating losses available to offset for financial statement purposes. NRG has accrued interest related to these uncertain tax benefits of approximately $10 million for the nine months ended September 30, 2010, and has accrued approximately $36 million since adoption. The Company recognizes interest and penalties related to uncertain tax benefits in income tax expense.

The examination by the Internal Revenue Service for the years 2004 through 2006 is currently in Joint Committee review and is not considered effectively settled in accordance with ASC 740. The Company anticipates conclusion of the audit by March 31, 2011. Upon effective settlement of the audit, the result may be a reduction of the liability for uncertain tax benefits. The Company continues to be under examination for various state jurisdictions for multiple years.

Tax Receivable and Payable

As of September 30, 2010, NRG recorded a current tax payable of $28 million that represents a tax liability due for domestic state taxes of $18 million, as well as foreign taxes payable of $10 million. In addition, as of September 30, 2010, NRG had a domestic tax receivable of $74 million for property tax refunds primarily due to the New York State Empire Zone program. On October 15, 2010, the Empire Zone Designation Board upheld the previous decertification of the Company’s Oswego facility from participating in the Empire Zone program. This decertification is effective from January 1, 2008 and prevents the facility from further participation in certain tax benefits provided by this program and associated with property taxes paid. The Company is considering its avenues of appeal, but believes it has adequately reserved for the outcome of this decision.

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, 2010, was $15 million. NRG expects to make approximately $3 million in additional contributions for the remainder of 2010.

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


	Defined Benefit Pension Plans
	Three months ended September 30,						Nine months ended September 30,
(In millions)	2010			2009			2010			2009

Service cost benefits earned	$	3		$	4		$	10		$	11
Interest cost on benefit obligation		6			5			16			15
Prior service cost		—			—			—			1
Expected return on plan assets		(5	)		(4	)		(15	)		(12	)

Net periodic benefit cost	$	4		$	5		$	11		$	15

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)	2010		2009		2010		2009

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

Net periodic benefit cost	$	3	$	3	$	7	$	7

STP Defined Benefit Plans

NRG has a 44% undivided ownership interest in South Texas Project, or STP. South Texas Project Nuclear Operating Company, or STPNOC, which operates and maintains STP, provides its employees a defined benefit pension plan as well as postretirement health and welfare benefits. Although NRG does not sponsor the STP plan, it reimburses STPNOC for 44% of the contributions made towards its retirement plan obligations. The total amount of employer contributions reimbursed to STPNOC for the nine months ended September 30, 2010, was $3 million.

The Company recognized net periodic costs related to its 44% interest in STP defined benefits as follows:


	Three months ended September 30,				Nine months ended September 30,
(In millions)	2010		2009		2010		2009

Net periodic benefit costs	$	2	$	3	$	6	$	8

Note 15 — Commitments and Contingencies

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, 2010, all hedges under the first and second liens were in-the-money on a counterparty aggregate basis.

Nuclear Innovation North America, LLC

CPS Settlement — On March 1, 2010, an agreement was reached with CPS for NINA to acquire a controlling interest in the STP Units 3 and 4 Project through a settlement of litigation between the parties. As part of the agreement, NINA increased its ownership in the STP Units 3 and 4 Project from 50% to 92.375% and assumed full management control of the project. NRG also will pay $80 million to CPS, subject to the United States Department of Energy’s, or U.S. DOE, approval of a fully executed term sheet for a conditional U.S. DOE loan guarantee. The first $40 million would be promptly paid after acceptance of the guarantee with the remaining $40 million paid six months later. NRG also agreed to donate an additional $10 million, unconditionally, over four years in annual payments of $2.5 million to the Residential Energy Assistance Partnership, or REAP, in San Antonio. The first $2.5 million payment to REAP was made on March 17, 2010. In connection with the agreement, the Company capitalized $90 million to construction in progress within property, plant and equipment, and as of September 30, 2010, $87.5 million in liabilities remains on the condensed consolidated balance sheet for the obligations to CPS and REAP. As part of the agreement with CPS, all litigation was dismissed with prejudice.

NINA Investment and Option Agreement — On May 10, 2010, NINA and TEPCO Nuclear Energy America LLC, or TNEA, a wholly-owned subsidiary of The Tokyo Electric Power Company of Japan, signed an Investment and Option Agreement whereby TNEA agreed to acquire up to a 20% interest in NINA Investments Holdings LLC, or Holdings, a wholly-owned subsidiary of NINA, which indirectly holds NINA’s ownership interest in the STP Units 3 and 4 Project. TNEA will initially invest $155 million for a 10% share of Holdings, which includes a $30 million option premium payment to Holdings. This option, which expires approximately one year from the date of signing the Investment and Option Agreement, will enable TNEA to buy an additional 10% of Holdings for another payment of $125 million. Pursuant to the terms of the Agreement, the closing is contingent upon NINA’s acceptance of a fully executed term sheet for a conditional U.S. DOE loan guarantee. Upon its initial investment, TNEA will hold a 9.238% interest in the STP Units 3 and 4 Project, diluting NINA’s investment to 83.137% (75.2% for NRG). If TNEA exercises its option to increase its ownership of Holdings another 10%, it will own 18.475% of the STP Units 3 and 4 Project, diluting NINA’s investment to 73.90% (66.8% for NRG).

U.S. DOE Loan Guarantee — In early 2010, NRG announced that if the STP Units 3 and 4 Project did not receive a loan guarantee from the U.S. DOE in a timely fashion, it was the intention of the Company both to reduce substantially its commitment to fund on-going project expenditures as well as to reduce development spending on the project overall while the outcome of the loan guarantee was uncertain. When the loan guarantee was not received and Congress went into its summer recess, NRG, after consultation with its partners, dramatically reduced its ongoing equity contributions into NINA for project development, but did so in a manner that allowed the project to stay on its current schedule. Should NRG and its partners unanimously agree to withdraw support from the project, this would result in a reassessment of the probability of success of the project and an impairment and permanent write-down of some or all of the value of the capitalized assets for STP Units 3 and 4. Through September 30, 2010, NRG has made equity contributions of $315 million into NINA. NINA has capitalized $624 million of construction-in-progress, of which $157 million was funded by Toshiba equity contributions and the TANE Facility, and $162 million is an accounts payable balance that NINA intends to primarily fund in the fourth quarter with the TANE Facility upon completion of amendments to that credit facility. The likelihood of NINA receiving a loan guarantee is largely dependent upon additional appropriations for nuclear development by Congress or other means of properly securing the necessary funding for additional nuclear loan guarantee volume.

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. NRG records reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. In addition, legal costs are expensed as incurred. Management has assessed each of the following matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, the Company is unable to predict the outcome of these legal proceedings or reasonably estimate the scope or amount of any associated costs and potential liabilities. As additional information becomes available, management adjusts its assessment and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of the Company’s liabilities and contingencies could be at amounts that are different from its currently recorded reserves and that such difference could be material.

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

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 January 14, 2010, the U.S. Supreme Court issued its decision in an unrelated proceeding involving the Mobile-Sierra doctrine that will affect the standard of review applied to the CDWR contract on remand before the FERC. In NRG Power Marketing v. Maine Public Utilities Commission, the Supreme Court held that the Mobile-Sierra presumption regarding the reasonableness of contract rates does not depend on the identity of the complainant who seeks a FERC investigation/refund.

Louisiana Generating, LLC

On February 11, 2009, the U.S. Department of Justice, or U.S. DOJ, acting at the request of the U.S. Environmental Protection Agency, or U.S. EPA, commenced a lawsuit against Louisiana Generating, LLC, or LaGen, 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 LaGen 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, LaGen made several filings. LaGen 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. LaGen also filed a complaint, or adversary proceeding, in the same bankruptcy proceeding, 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 with respect to environment liabilities arising prior to the acquisition; and (iii) Cajun Electric and/or the Bankruptcy Trustee are exclusively liable for any of the violations alleged in the February 11, 2009, lawsuit to the extent that such claims are determined to have merit. On April 15, 2010, the bankruptcy court signed an order granting LaGen’s stipulation of voluntary dismissal without prejudice of the adversary proceeding. The bankruptcy proceeding has since closed.

On June 8, 2009, the parties filed a joint status report in the U.S. DOJ lawsuit setting forth their views of the case and proposing a trial schedule. On April 28, 2010, the district court entered a Joint Case Management Order, in which the district court tentatively scheduled trial on a liability phase for mid-2011 and, if necessary, trial on the damages (remedy) phase for mid-2012. These dates are subject to change.

On August 24, 2009, LaGen filed a motion to dismiss this lawsuit, and on September 25, 2009, the U.S. DOJ filed its opposition to the motion. Thereafter, on February 18, 2010, the Louisiana Department of Environmental Quality, or LDEQ, filed a motion to intervene in the above lawsuit and a complaint against LaGen for alleged violations of Louisiana’s Prevention of Significant Deterioration, or PSD regulations and Louisiana’s Title V operating permit program. LDEQ seeks substantially similar relief to that requested by the U.S. DOJ. On February 19, 2010, the district court granted LDEQ’s motion to intervene. LDEQ is subject to the April 28, 2010 Joint Case Management Order in this matter. Also on April 26, 2010, LaGen filed a motion to dismiss the LDEQ complaint. On July 21, 2010, LaGen argued its motions to dismiss the U.S. DOJ and LDEQ complaints to the district court, while the U.S. DOJ and LDEQ argued in opposition to the motions. On August 20, 2010, the parties submitted proposed findings of fact and conclusions of law, and both parties have submitted additional briefing on emerging jurisprudence from other jurisdictions touching on the issues at stake in the U.S. DOJ lawsuit.

Dunkirk Construction Litigation

In 2005, NRG entered into a Consent Decree with the New York State Department of Environmental Conservation whereby it agreed to reduce certain emissions generated by its Huntley and Dunkirk power plants. Pursuant to the Consent Decree, on November 21, 2007, Clyde Bergemann EEC, or CBEEC, and NRG entered into a firm fixed price contract for the supply of equipment, material and services for six fabric filters for NRG’s Dunkirk Electric Power Generating Station. Subsequent to contracting with NRG, CBEEC subcontracted with Hohl Industrial Services, Inc., or Hohl, to perform steel erection and equipment installation at Dunkirk.

On August 28, 2009, Hohl filed its original complaint against NRG, its subsidiary Dunkirk Power LLC, or Dunkirk Power, and CBEEC among others for claims of breach of contract, quantum meruit, unjust enrichment and foreclosure of mechanics’ liens. As part of CBEEC’s contractual obligation to NRG, CBEEC agreed to defend NRG, under a reservation of rights. CBEEC filed an answer to the above complaint on behalf of itself, NRG, and Dunkirk Power on October 5, 2009. On December 16, 2009, CBEEC filed a Motion for Summary Judgment on behalf of itself, NRG, and Dunkirk Power. On February 1, 2010, NRG and Dunkirk Power filed a Motion for Leave to file an Amended Answer with Cross-Claims against CBEEC. NRG asserted breach of contract claims seeking liquidated damages for the delays caused by CBEEC. NRG also retained its own counsel to represent its interest in the cross-claims and reserved its rights to seek reimbursement from CBEEC. On February 17, 2010, CBEEC filed an Amended Answer with Affirmative Defenses, Counterclaims and Cross-Claims against NRG, in which it sought $30 million alleging breach of contract, quantum meruit, unjust enrichment, and foreclosure of two mechanic’s liens, as a result of alleged delays caused by NRG and Dunkirk Power. On March 5, 2010, CBEEC and NRG resolved their disputed cross-claims. In April 2010, the other parties to this litigation settled their disputes. A final dismissal order is expected shortly.

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 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 Reliant Energy Inc., or REI, 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.

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 — 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 Reliability Pricing Model, or 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. The case has been transferred to the U.S. Court of Appeals for the D.C. Circuit. Oral argument is scheduled for November 15, 2010.

Midwest ISO v. PJM — On March 8, 2010, Midwest ISO filed a complaint against PJM seeking payments from PJM related to inter-market operations and settlements for congestion costs between the systems for the period from April 2005 to the present. If the Midwest ISO’s allegations are true, PJM may have significant liability. If PJM makes any payments to the Midwest ISO related to these claims, PJM is expected to seek to recover the payments from entities that served load and held transmission congestion rights on PJM during the period in dispute, including NRG, which provided basic generation service and thus effectively served load. At this time, NRG’s share of any payment by PJM is not expected to be material.

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. 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. On October 6, 2010, the parties argued the appeal before the Court of Appeals for the Third District in Austin, Texas.

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.

California — On May 4, 2010, in Southern California Edison Company v. FERC, the U.S. Court of Appeals for the D.C. Circuit vacated FERC’s acceptance of station power rules for the CAISO market, and remanded the case for further proceedings at FERC. On August 30, 2010, FERC issued an Order on Remand effectively disclaiming jurisdiction over how the states impose retail station power charges. Due to reservation-of-rights language in the California utilities’ state-jurisdictional station power tariffs, FERC’s ruling effectively requires California generators to pay state-imposed retail charges back to the date of enrollment by the facilities in the CAISO’s station period program (February 1, 2009 for the Company’s Encina and El Segundo facilities; March 1, 2009 for the Company’s Long Beach facility). Although requests for rehearing have been submitted, the Company has established an appropriate reserve.

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 U.S. If such laws and regulations become more stringent, or new laws, interpretations or compliance policies apply and NRG’s facilities are not exempt from coverage, the Company could be required to make modifications to further reduce potential environmental impacts. 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 2014 to meet NRG’s environmental commitments will be approximately $0.9 billion 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, sulfur dioxide, or SO₂, nitrogen oxide, or 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 a section of the Clean Water Act regulating cooling water intake structures, or Phase II 316(b) Rule. NRG continues to explore cost effective compliance alternatives. This estimate reflects anticipated schedules and controls related to the Clean Air Interstate Rule, or CAIR, the proposed Clean Air Transport Rule, or CATR, 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.

NRG’s current contracts with the Company’s rural electrical customers in the South Central region allow for recovery of a portion of the regions’ capital costs once in operation, along with a capital return incurred by complying with any change in law, including interest over the asset life of the required expenditures. The actual recoveries will depend, among other things, on the timing of the completion of the capital project and the remaining duration of the contracts.

Northeast Region

In January 2006, NRG’s Indian River Operations, Inc. received a letter of informal notification from Delaware Department of Natural Resources and Environmental Control, or DNREC, stating that it may be a potentially responsible party with respect to Burton Island Old Ash Landfill, a historic captive landfill located at the Indian River facility. On October 1, 2007, NRG signed an agreement with DNREC to investigate the site through the Voluntary Clean-up Program. On February 4, 2008, DNREC issued findings that no further action is required in relation to surface water and that a previously planned shoreline stabilization project would satisfactorily 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, 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 DNREC and other trustees to close out the assessment phase.

Pursuant to a consent order dated September 25, 2007, between NRG and DNREC, NRG agreed to operate the four units at the Indian River plant in a manner that would limit the emissions of NO_x and SO₂, and to mothball Units 1 and 2 on May 1, 2011, and May 1, 2010, respectively. In addition, Units 3 and 4, with a combined generating capacity of approximately 565 MW, could not operate beyond December 31, 2011, unless appropriate control technology was installed on each unit. Unit 2 was mothballed as planned on May 1, 2010. On July 21, 2010, the court approved an amended consent order, pursuant to which NRG will retire Unit 3 (155 MW) by December 31, 2013, thereby extending the operable period of the unit by two years without installing additional control technology. Units 1, 2 and 4 are not affected by the amended consent order.

South Central Region

On February 11, 2009, the U.S. DOJ acting at the request of the U.S. EPA commenced a lawsuit against LaGen 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 LaGen 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 — Condensed Consolidating Financial Information

As of September 30, 2010, 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, $700 million of 8.50% Senior Notes due 2019, and $1.1 billion of 8.25% Senior Notes due 2020. These notes are guaranteed by certain of NRG’s current and future wholly-owned domestic subsidiaries, or guarantor subsidiaries.

Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of September 30, 2010:


Arthur Kill Power LLC		NRG Generation Holdings, Inc.
Astoria Gas Turbine Power LLC		NRG Huntley Operations Inc.
Berrians I Gas Turbine Power LLC		NRG International LLC
Big Cajun II Unit 4 LLC		NRG MidAtlantic Affiliate Services Inc.
Cabrillo Power I LLC		NRG Middletown Operations Inc.
Cabrillo Power II LLC		NRG Montville Operations Inc.
Carbon Management Solutions LLC		NRG New Jersey Energy Sales LLC
Clean Edge Energy LLC		NRG New Roads Holdings LLC
Conemaugh Power LLC		NRG North Central Operations, Inc.
Connecticut Jet Power LLC		NRG Northeast Affiliate Services Inc.
Devon Power LLC		NRG Norwalk Harbor Operations Inc.
Dunkirk Power LLC		NRG Operating Services Inc.
Eastern Sierra Energy Company		NRG Oswego Harbor Power Operations Inc.
Elbow Creek Wind Project LLC		NRG Power Marketing LLC
El Segundo Power, LLC		NRG Retail LLC
El Segundo Power II LLC		NRG Saguaro Operations Inc.
GCP Funding Company LLC		NRG South Central Affiliate Services Inc.
Huntley IGCC LLC		NRG South Central Generating LLC
Huntley Power LLC		NRG South Central Operations Inc.
Indian River IGCC LLC		NRG South Texas LP
Indian River Operations Inc.		NRG Texas LLC
Indian River Power LLC		NRG Texas C & I Supply LLC
James River Power LLC		NRG Texas Holding Inc.
Keystone Power LLC		NRG Texas Power LLC
Langford Wind Power, LLC		NRG West Coast LLC
Louisiana Generating LLC		NRG Western Affiliate Services Inc.
Middletown Power LLC		Oswego Harbor Power LLC
Montville IGCC LLC		Pennywise Power LLC
Montville Power LLC		Reliant Energy Power Supply, LLC
NEO Corporation		Reliant Energy Retail Holdings, LLC
NEO Freehold-Gen LLC		Reliant Energy Retail Services, LLC
NEO Power Services Inc.		RE Retail Receivables, LLC
New Genco GP LLC		RERH Holdings, LLC
Norwalk Power LLC		Reliant Energy Texas Retail LLC
NRG Affiliate Services Inc.		Saguaro Power LLC
NRG Arthur Kill Operations Inc.		Somerset Operations Inc.
NRG Artesian Energy LLC		Somerset Power LLC
NRG Astoria Gas Turbine Operations Inc.		Texas Genco Financing Corp.
NRG Bayou Cove LLC		Texas Genco GP, LLC
NRG Cabrillo Power Operations Inc.		Texas Genco Holdings, Inc.
NRG California Peaker Operations LLC		Texas Genco LP, LLC
NRG Cedar Bayou Development Company LLC		Texas Genco Operating Services, LLC
NRG Connecticut Affiliate Services Inc.		Texas Genco Services, LP
NRG Construction LLC		Vienna Operations, Inc.
NRG Devon Operations Inc.		Vienna Power LLC
NRG Dunkirk Operations, Inc.		WCP (Generation) Holdings LLC
NRG Energy Services LLC		West Coast Power LLC
NRG El Segundo Operations Inc.

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

The following condensed consolidating financial information presents the financial information of NRG, 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, 2010


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

Operating Revenues
Total operating revenues	$	2,589	$	101		$	—		$	(5	)	$	2,685

Operating Costs and Expenses
Cost of operations		1,775		65			—			(5	)		1,835
Depreciation and amortization		198		9			3			—			210
Selling, general and administrative		99		5			68			—			172
Development costs		—		2			12			—			14

Total operating costs and expenses		2,072		81			83			(5	)		2,231

Operating Income/(Loss)		517		20			(83	)		—			454
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries		8		—			365			(373	)		—
Equity in earnings of unconsolidated affiliates		4		12			—			—			16
Other income, net		1		6			4			—			11
Interest income/(expense)		1		(14	)		(156	)		—			(169	)

Total other income/(expense)		14		4			213			(373	)		(142	)

Income/(Loss) Before Income Taxes		531		24			130			(373	)		312
Income tax expense/(benefit)		178		4			(93	)		—			89

Net income/(loss) attributable to NRG Energy, Inc.	$	353	$	20		$	223		$	(373	)	$	223


(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, 2010


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

Operating Revenues
Total operating revenues	$	6,782		$	270		$	—		$	(19	)	$	7,033

Operating Costs and Expenses
Cost of operations		4,631			184			7			(19	)		4,803
Depreciation and amortization		590			23			7			—			620
Selling general and administrative		238			10			193			—			441
Development costs		—			8			28			—			36

Total operating costs and expenses		5,459			225			235			(19	)		5,900

Gain on sale of assets		—			—			23			—			23

Operating Income/(Loss)		1,323			45			(212	)		—			1,156
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries		30			—			891			(921	)		—
Equity in earnings of unconsolidated affiliates		5			36			—			—			41
Other income, net		4			23			7			—			34
Interest expense		(10	)		(37	)		(422	)		—			(469	)

Total other income/(expense)		29			22			476			(921	)		(394	)

Income/(Loss) Before Income Taxes		1,352			67			264			(921	)		762
Income tax expense/(benefit)		479			20			(228	)		—			271

Net Income/(Loss)		873			47			492			(921	)		491
Less: Net loss attributable to noncontrolling interest		(1	)		—			—			—			(1	)

Net income/(loss) attributable to NRG Energy, Inc.	$	874		$	47		$	492		$	(921	)	$	492


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

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
September 30, 2010


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

ASSETS
Current Assets
Cash and cash equivalents	$	25		$	119		$	3,303		$	—		$	3,447
Funds deposited by counterparties		457			—			—			—			457
Restricted cash		—			19			—			—			19
Accounts receivable, net		863			41			—			—			904
Inventory		455			8			—			—			463
Derivative instruments valuation		2,479			—			—			—			2,479
Cash collateral paid in support of energy risk management activities		475			2			—			—			477
Prepayments and other current assets		63			41			289			(143	)		250

Total current assets		4,817			230			3,592			(143	)		8,496

Net property, plant and equipment		10,412			1,274			158			—			11,844

Other Assets
Investment in subsidiaries		806			253			21,251			(22,310	)		—
Equity investments in affiliates		45			465			—			—			510
Note receivable – affiliate and capital leases, less current portion		6,148			399			3,239			(9,384	)		402
Goodwill		1,713			—			—			—			1,713
Intangible assets, net		1,481			58			33			(31	)		1,541
Nuclear decommissioning trust fund		389			—			—			—			389
Derivative instruments valuation		993			—			8			—			1,001
Restricted cash supporting funded letter of credit facility		—			1,301			—			—			1,301
Other non-current assets		53			14			155			—			222

Total other assets		11,628			2,490			24,686			(31,725	)		7,079

Total Assets	$	26,857		$	3,994		$	28,436		$	(31,868	)	$	27,419


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	58		$	131		$	26		$	(58	)	$	157
Accounts payable		(3,375	)		535			3,605			—			765
Derivative instruments valuation		2,034			4			34			—			2,072
Deferred income taxes		738			6			(363	)		—			381
Cash collateral received in support of energy risk management activities		457			—			—			—			457
Accrued expenses and other current liabilities		433			46			256			(85	)		650

Total current liabilities		345			722			3,558			(143	)		4,482

Other Liabilities
Long-term debt and capital leases		2,939			908			14,600			(9,384	)		9,063
Funded letter of credit		—			—			1,300			—			1,300
Nuclear decommissioning reserve		313			—			—			—			313
Nuclear decommissioning trust liability		256			—			—			—			256
Deferred income taxes		1,675			(165	)		237			—			1,747
Derivative instruments valuation		414			47			39			—			500
Out-of-market contracts		259			7			—			(31	)		235
Other non-current liabilities		775			29			250			—			1,054

Total non-current liabilities		6,631			826			16,426			(9,415	)		14,468

Total liabilities		6,976			1,548			19,984			(9,558	)		18,950

3.625% Preferred Stock		—			—			248			—			248
Total Stockholders’ Equity		19,881			2,446			8,204			(22,310	)		8,221

Total Liabilities and Stockholders’ Equity	$	26,857		$	3,994		$	28,436		$	(31,868	)	$	27,419


(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, 2010


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

Cash Flows from Operating Activities
Net income	$	873		$	47		$	492		$	(921	)	$	491
Adjustments to reconcile net income to net cash provided by operating activities:
Distributions and equity in (earnings)/losses of unconsolidated affiliates and consolidated subsidiaries		12			(17	)		(854	)		840			(19	)
Depreciation and amortization		590			23			7			—			620
Provision for bad debts		46			—			—			—			46
Amortization of nuclear fuel		30			—			—			—			30
Amortization of financing costs and debt discount/premiums		—			5			18			—			23
Amortization of intangibles and out-of-market contracts		(17	)		—			—			—			(17	)
Changes in deferred income taxes and liability for uncertain tax benefits		480			3			(211	)		—			272
Changes in nuclear decommissioning trust liability		26			—			—			—			26
Changes in derivatives		(48	)		—			—			—			(48	)
Changes in collateral deposits supporting energy risk management activities		(116	)		—			—			—			(116	)
Loss/(gain) on sale and disposal of assets		17			—			(23	)		—			(6	)
Loss on sale of emission allowances		4			—			—			—			4
Amortization of unearned equity compensation		—			—			23			—			23
Changes in option premiums collected, net of acquisition		60			—			—			—			60
Cash (used)/provided by changes in other working capital, net of acquisitions		(632	)		(82	)		466			—			(248	)

Net Cash Provided/(Used) by Operating Activities		1,325			(21	)		(82	)		(81	)		1,141

Cash Flows from Investing Activities
Intercompany (loans to)/receipts from subsidiaries		(1,261	)		—			(212	)		1,473			—
Acquisition of businesses		—			(142	)		—			—			(142	)
Investment in subsidiaries		—			1,724			(1,724	)		—			—
Capital expenditures		(223	)		(224	)		(43	)		—			(490	)
Decrease/(increase) in restricted cash, net		1			(18	)		—			—			(17	)
Decrease in notes receivable		—			28			—			—			28
Purchases of emission allowances		(56	)		—			—			—			(56	)
Proceeds from sale of emission allowances		14			—			—			—			14
Investments in nuclear decommissioning trust fund securities		(245	)		—			—			—			(245	)
Proceeds from sales of nuclear decommissioning trust fund securities		219			—			—			—			219
Proceeds from renewable energy grants		84			18			—			—			102
Proceeds from sale of assets, net		1			—			29			—			30
Other		—			(16	)		3			—			(13	)

Net Cash (Used)/Provided by Investing Activities		(1,466	)		1,370			(1,947	)		1,473			(570	)

Cash Flows from Financing Activities
(Payments)/proceeds from intercompany loans		126			86			1,261			(1,473	)		—
Payment of inter-company dividends		(44	)		(37	)		—			81			—
Payment of dividends to preferred stockholders		—			—			(7	)		—			(7	)
Payments for treasury stock		—			—			(180	)		—			(180	)
Net receipt from acquired derivatives that include financing elements		58			—			—			—			58
Installment proceeds from sale of noncontrolling interest in subsidiary		—			50			—			—			50
Proceeds from issuance of long-term debt		7			145			1,100			—			1,252
Proceeds from issuance of term loan for funded letter of credit facility		—			—			1,300			—			1,300
Increase in restricted cash supporting funded letter of credit facility		—			(1,301	)		—			—			(1,301	)
Proceeds from issuance of common stock		—			—			2			—			2
Payment of deferred debt issuance costs		(1	)		(8	)		(61	)		—			(70	)
Payment of short and long-term debt		—			(282	)		(247	)		—			(529	)

Net Cash Provided/(Used) by Financing Activities		146			(1,347	)		3,168			(1,392	)		575
Effect of exchange rate changes on cash and cash equivalents		—			(3	)		—			—			(3	)

Net Increase/(Decrease) in Cash and Cash Equivalents		5			(1	)		1,139			—			1,143
Cash and Cash Equivalents at Beginning of Period		20			120			2,164			—			2,304

Cash and Cash Equivalents at End of Period	$	25		$	119		$	3,303		$	—		$	3,447


(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, 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/(expense), net		2			2			4			(3	)		5
Interest expense		(5	)		(38	)		(135	)		—			(178	)

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

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

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/(expense), net		5			(17	)		6			(3	)		(9	)
Interest expense		(71	)		(97	)		(307	)		—			(475	)

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

Income/(Loss) 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
December 31, 2009


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

ASSETS
Current Assets
Cash and cash equivalents	$	20		$	120		$	2,164		$	—		$	2,304
Funds deposited by counterparties		177			—			—			—			177
Restricted cash		1			1			—			—			2
Accounts receivable-trade, net		837			39			—			—			876
Inventory		529			12			—			—			541
Derivative instruments valuation		1,636			—			—			—			1,636
Cash collateral paid in support of energy risk management activities		359			2			—			—			361
Prepayments and other current assets		194			61			157			(101	)		311

Total current assets		3,753			235			2,321			(101	)		6,208

Net Property, Plant and Equipment		10,494			1,009			61			—			11,564

Other Assets
Investment in subsidiaries		613			222			16,862			(17,697	)		—
Equity investments in affiliates		42			367			—			—			409
Note receivable – affiliate and capital leases, less current portion		4,982			504			3,027			(8,009	)		504
Goodwill		1,718			—			—			—			1,718
Intangible assets, net		1,755			20			33			(31	)		1,777
Nuclear decommissioning trust fund		367			—			—			—			367
Derivative instruments valuation		718			—			8			(43	)		683
Other non-current assets		29			8			111			—			148

Total other assets		10,224			1,121			20,041			(25,780	)		5,606

Total Assets	$	24,471		$	2,365		$	22,423		$	(25,881	)	$	23,378


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	58		$	310		$	261		$	(58	)	$	571
Accounts payable		(852	)		393			1,156			—			697
Derivative instruments valuation		1,469			2			2			—			1,473
Deferred income taxes		456			11			(270	)		—			197
Cash collateral received in support of energy risk management activities		177			—			—			—			177
Accrued expenses and other current liabilities		261			82			347			(43	)		647

Total current liabilities		1,569			798			1,496			(101	)		3,762

Other Liabilities
Long-term debt and capital leases		2,533			1,003			12,320			(8,009	)		7,847
Nuclear decommissioning reserve		300			—			—			—			300
Nuclear decommissioning trust liability		255			—			—			—			255
Deferred income taxes		1,711			(165	)		237			—			1,783
Derivative instruments valuation		323			28			79			(43	)		387
Out-of-market contracts		318			7			—			(31	)		294
Other non-current liabilities		431			16			359			—			806

Total non-current liabilities		5,871			889			12,995			(8,083	)		11,672

Total liabilities		7,440			1,687			14,491			(8,184	)		15,434

3.625% Preferred Stock		—			—			247			—			247
Total Stockholders’ Equity		17,031			678			7,685			(17,697	)		7,697

Total Liabilities and Stockholders’ Equity	$	24,471		$	2,365		$	22,423		$	(25,881	)	$	23,378


(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 uncertain tax benefits		(46	)		6			601			—			561
Changes in nuclear decommissioning trust liability		19			—			—			—			19
Changes in derivatives		(32	)		(202	)		—			—			(234	)
Changes in collateral deposits supporting energy risk management activities		266			(253	)		—			—			13
Loss on sale and disposal 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 premium collected		(266	)		(12	)		—			—			(278	)
Cash provided/(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
Investment 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
Proceeds from sale of equity method investment		—			284			—			—			284
Other		(1	)		—			(5	)		—			(6	)

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

Cash Flows from Financing Activities
(Payments)/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		—			—			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 Equivalent		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.

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

As you read this discussion and analysis, refer to the Company’s Condensed Consolidated Statements of Operations to this Form 10-Q, which present the results of operations for the three and nine months ended September 30, 2010, and 2009. Also refer to NRG’s Annual Report on Form 10-K for the year ended December 31, 2009, or 2009 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;

	•		Financial condition addressing liquidity position, sources and uses of liquidity, 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.

Executive Summary

Introduction and Overview

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 U.S., as well as a major retail electricity provider in the ERCOT (Texas) market through Reliant Energy. NRG is engaged in the ownership, development, construction and operation of power generation facilities, both conventional and renewable, the transacting in and trading of fuel and transportation services, the trading of energy, capacity and related products in the U.S. and select international markets, and the supply of electricity and energy services to retail electricity customers in the Texas market.

As of September 30, 2010, NRG had a total global generation portfolio of 188 active operating fossil fuel and nuclear generation units, at 44 power generation plants, with an aggregate generation capacity of approximately 24,010 MW, and approximately 245 MW under construction which includes partner interests of 120 MW. In addition to its fossil fuel plant ownership, NRG has ownership interests in operating renewable facilities with an aggregate generation capacity of 465 MW, consisting of four wind farms representing an aggregate generation capacity of 445 MW and a 20 MW solar facility. Within the U.S., NRG has large and diversified power generation portfolios in terms of geography, fuel-type and dispatch levels, with approximately 23,005 MW of fossil fuel and nuclear generation capacity in 180 active generating units at 42 plants. The Company’s power generation facilities are most heavily concentrated in Texas (approximately 11,440 MW, including 445 MW from four wind farms), the Northeast (approximately 6,910 MW), South Central (approximately 2,855 MW), and West (approximately 2,150 MW, including 20 MW from a solar facility) regions of the U.S., with approximately 115 MW of additional generation capacity from the Company’s thermal assets. In addition, through certain foreign subsidiaries, NRG has investments in power generation projects located in Australia and Germany with approximately 1,005 MW of generation capacity.

NRG’s principal domestic power plants consist of a mix of natural gas-, coal-, oil-fired, nuclear and renewable facilities, representing approximately 45%, 31%, 17%, 5% and 2% of the Company’s total domestic generation capacity, respectively. In addition, 9% of NRG’s domestic generating facilities have dual or multiple fuel capacity, which allows those 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 the 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.

Reliant Energy, the Company’s retail electricity provider, 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. Based on metered locations, as of September 30, 2010, Reliant Energy had approximately 1.5 million customers.

Furthermore, 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. These investments include low or no GHG emitting energy generating sources, such as nuclear, wind, solar thermal, photovoltaic, biomass, “clean” coal and gasification; the retrofit of post-combustion carbon capture technologies; and developments in the electric vehicle ecosystem.

NRG’s Business Strategy

NRG’s business strategy is intended to maximize shareholder value through the production and sale of safe, reliable and affordable power to its customers in the markets served by the Company, while aggressively positioning the Company to meet the market’s increasing demand for sustainable and low carbon energy solutions. This dual strategy is designed to perfect the Company’s core business of competitive power generation and establish the Company as a leading provider of sustainable energy solutions that promote national energy security, while utilizing the Company’s retail business to complement and advance both initiatives.

The Company’s core business is focused on: (i) top decile operating performance of its existing operating assets, (ii) optimal hedging of baseload and retail operations, while retaining optionality on the Company’s gas fleet, (iii) repowering of power generation assets at existing sites and reducing environmental impacts, (iv) pursuit of selective acquisitions, joint ventures, divestitures and investments, 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.

In addition, the Company believes in promoting national energy security and that success in providing energy solutions that address sustainability and climate change concerns will not only reduce the carbon and capital intensity of the Company in the future, it also will reduce the real and perceived linkage between the Company’s financial performance and prospects, and volatile commodity prices, particularly with respect to natural gas. The Company’s initiatives in this area of future growth are focused on: (i) low carbon baseload – primarily nuclear generation, (ii) renewables, with a concentration in solar and wind generation and development, (iii) fast start, high efficiency gas-fired capacity in the Company’s core regions, (iv) electric vehicle ecosystems, and (v) smart grid services. The Company’s advancements in each of these areas are driven by select acquisitions, joint ventures, and investments that are more fully described in the Company’s 2009 Form 10-K, the Quarterly Reports on Form 10-Q for the quarters ended June 30, 2010, and March 31, 2010, and this Form 10-Q.

Environmental Matters

Environmental Regulatory Landscape

A number of regulations that could significantly impact the power generation industry are in development or under review by the U.S. EPA: CAIR/CATR, MACT, NAAQS revisions, coal combustion byproducts, and once-through cooling. While most of these regulations have been considered for some time, they are expected to gain clarity in 2010 through 2011. The timing and stringency of these regulations will provide a framework for the retrofit of existing fossil plants and deployment of new, cleaner technologies in the next decade. The Company has included capital to meet anticipated CAIR Phase I and II, proposed CATR, MACT standards for mercury, and the installation of “Best Technology Available” under the 316(b) Rule in the current estimated environmental capital expenditure. While the Company cannot predict the impact of future regulations and would likely face additional investments over time, these expenditures, combined with the Company’s already existing air quality controls, use of Powder River Basin coal, closed cycle cooling, and dry ash handling systems position NRG well to meet more stringent requirements.

The U.S. EPA released the proposed CATR on July 6, 2010. This rule is designed to replace CAIR and address the findings of the U.S. Court of Appeals for the D.C. Circuit that initially vacated the rule. The rule is designed to bring 31 states and Washington, D.C. into attainment with PM 2.5 and ozone national ambient air quality standards through emission reductions in SO₂ and NO_x. Proposed implementation would be through a cap and trade program starting in 2012 with constrained trading between states in the CATR regions. In 2014, the SO₂cap would be further reduced in certain states. Under CATR, use of discounted Acid Rain SO₂ allowances would be discontinued and replaced with a completely distinct CATR SO₂ allowance program. Acid Rain allowances would still be required on a 1:1 basis under the Acid Rain Program. NRG continues to evaluate the proposed rule and any impact it has to emission markets and currently estimates that the proposed rule, if it becomes effective, could result in up to a $50 million future impairment of the Company’s SO₂ emission allowance, which is recorded as an intangible asset on the Company’s balance sheet. NRG’s planned environmental capital expenditures are consistent with reductions anticipated in the rule.

The New York State Department of Environmental Conservation finalized the NO_x Reasonably Available Control Technology, or RACT, Rule on July 14, 2010. This rule identifies new NO_x emission limits for major sources which must be met by July 1, 2014. Plants can comply or request an alternate RACT limit. All of NRG’s facilities are able to meet the new standards with the exception of the Oswego plant, which will apply for an alternate limit.

On May 4, 2010, the U.S. EPA proposed two options for the regulation of coal combustion residue, commonly known as coal ash. Under the Proposal’s first regulatory option, the U.S. EPA would reverse its August 1993 and May 2000 Bevill Regulatory Determinations and list coal ash as a special waste subject to regulation under hazardous waste regulations. The second regulatory option would leave the Bevill Determination in place and regulate disposal of coal ash as non-hazardous. Under both options, an exemption for the beneficial use of coal ash would remain in place. Additionally, under both options, the U.S. EPA would establish dam safety requirements to address the structural integrity of surface impoundments. While it is not possible to predict the impact of this rule until it is final, as proposed it is not expected to have a material impact on NRG’s operations, as all flyash disposal sites are dry landfills. However, should the U.S. EPA implement the hazardous waste option, NRG may incur significant costs due to loss of markets for beneficial reuse. Given the recent release of this proposed rule, NRG will continue to monitor developments and their respective impact on the Company’s operations.

The California statewide 316(b) policy to mitigate once-through cooling was effective as of October 1, 2010. Options for power plants with once-through cooling include transitioning to a closed loop system, retirement or submitting an alternative plan that meets equivalent mitigation criteria. Specified compliance dates for NRG’s El Segundo and Encina power plants are December 31, 2015, and December 31, 2017, respectively. NRG is analyzing compliance through a mix of alternative mitigation plans and repowering.

In June 2010, the U.S. EPA issued a Section 308 Information Collection Request to steam electric power generating plants across the industry, including 13 NRG facilities. The questionnaire focuses on water and wastewater discharges from power plants. The U.S. EPA indicated results will be used to develop new effluent guidelines for the industry.

Finalization of the Endangerment Finding, a rule addressing tailpipe limitations for light duty vehicles, and a final interpretation of the Johnson Memorandum set the stage for regulation of GHGs from stationary sources. On June 3, 2010, the U.S. EPA published the final rule tailoring the applicability criteria that determine which new and modified sources will become subject to permitting requirements for GHGs under the Prevention of Significant Deterioration, or PSD and Title V programs of the CAA. The rule raised applicability triggers to 75,000 or 100,000 tons per year CO₂ equivalents, or CO₂e, and implemented the requirements in two phases on January 2, 2011, or July 2, 2011. The immediate impact to NRG’s new and modified facilities is not expected to be material; the Company will continue to evaluate the potential long-term impact as regulatory programs are implemented over time.

Climate Change Legislation

In 2009, in the course of producing approximately 71 million MWh of electricity, NRG’s power plants emitted 59 million tonnes of CO₂, of which 53 million tonnes were emitted in the U.S., 3 million tonnes in Germany and 3 million tonnes in Australia. During the same period, NRG emitted approximately 8 million tons of CO₂ in the RGGI region. The impact from legislation or federal, regional or state regulation of GHGs on the Company’s financial performance will depend on a number of factors, including the overall level of GHG reductions required under any such regulations, the price and availability of offsets, 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, under any such legislation or regulation, the impact on NRG would depend on the Company’s level of success in developing and deploying low and no carbon technologies such as those being pursued as discussed in the above.

Congress has been unable to come to an agreement on climate legislation during this session. Lack of legislation will prolong the uncertainty of the nature and timing of GHG requirements and their resulting impact on NRG.

Regulatory Matters

As operators of power plants and participants in wholesale energy markets, certain NRG entities are subject to regulation by various federal and state government agencies. These include the U.S. Commodity Futures Trading Commission, or CFTC, FERC, U.S. Nuclear Regulatory Commission, or NRC, PUCT and other public utility commissions in certain states where NRG’s generating or thermal assets are located. In addition, NRG is subject to the market rules, procedures and protocols of the various ISO markets in which it participates. Certain of the Reliant Energy entities are competitive Retail Electric Providers, or REPs, and as such are subject to the rules and regulations of the PUCT governing REPs. NRG must also comply with the mandatory reliability requirements imposed by the North American Electric Reliability Corporation, or NERC, and the regional reliability councils in the regions where the Company operates. The operations of, and wholesale electric sales from, NRG’s Texas region are not subject to rate regulation by the FERC, as they are deemed to operate solely within the ERCOT market and not in interstate commerce.

Financial Reform — On July 21, 2010, President Obama signed the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which, among other things, aims to improve transparency and accountability in derivative markets. While the Dodd-Frank Act increases the CFTC’s regulatory authority over over-the-counter derivatives, there is uncertainty on several issues related to market clearing, definitions of market participants, reporting, and capital requirements. While there are many details that remain to be addressed in CFTC rulemaking proceedings, at this time the Company does not anticipate any material impact on its current operations or collateral requirements. NRG’s view is informed by a letter dated June 30, 2010, from Senate Banking Committee Chairman Dodd and Senate Agriculture Committee Chairman Lincoln clarifying that the legislative intent of the Dodd-Frank Act is not to impose margin requirements on end users that use swaps to hedge or mitigate commercial risks. Depending on the outcome of the pending and expected rulemakings, however, there could be impacts on the Company’s future hedging strategy and collateral requirements.

New England — On February 22, 2010, ISO-NE filed proposed amendments to its Forward Capacity Market, or FCM, design with FERC. A number of generators protested the ISO-NE filing, arguing that FERC should not accept the proposed amendments. On March 23, 2010, an association of generators filed a complaint alleging that the proposed FCM amendments are not just and reasonable due to market distortions such as out-of-market contracts, and thus would continue to under-compensate capacity suppliers in New England. On April 2, 2010, NRG and PSEG jointly filed a second complaint alleging that the existing FCM market fails to adequately establish zonal prices and thus does not adequately compensate suppliers for the locational value of their capacity. These complaints are seeking only prospective relief. Any changes to the FCM market in response to these complaints could benefit from the Company’s existing New England assets in future FCM auctions. On April 23, 2010, FERC issued an order consolidating the proceedings. In its order, FERC accepted some of the ISO-NE’s proposed changes, but also set several of the central issues for hearing and settlement processes.

New York — On October 12, 2010, FERC approved new mitigation measures filed by the NYISO that apply when a unit in the rest-of-state region is dispatched out-of-merit for reliability. The Company’s resources in the rest-of-state region are dispatched out-of-merit for reliability from time to time.

California — On May 4, 2010, in Southern California Edison Company v. FERC, the U.S. Court of Appeals for the D.C. Circuit vacated FERC’s acceptance of station power rules for the CAISO market, and remanded the case for further proceedings at FERC. On August 30, 2010, FERC issued an Order on Remand effectively disclaiming jurisdiction over how the states impose retail station power charges. As a result of FERC’s decision, NRG’s power plants may be prevented from netting their station power consumption against their sales on a monthly basis not only in California but also in other markets, which could require NRG to purchase station power at retail rates.

Changes in Accounting Standards

See Note 2, Summary of Significant Accounting Policies, to this Form 10-Q 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)	2010			2009			Change %			2010			2009			Change %

Operating Revenues
Energy revenue ^(a)	$	810		$	992			(18	)%	$	2,191		$	2,905			(25	)%
Capacity revenue ^(a)		216			275			(21	)		628			786			(20	)
Retail revenue		1,593			1,876			(15	)		4,179			3,126			34
Mark-to-market activities		27			(217	)		112			13			(100	)		113
Other revenue		39			(10	)		490			22			94			(77	)

Total operating revenues		2,685			2,916			(8	)		7,033			6,811			3

Operating Costs and Expenses
Generation cost of sales ^(a)		720			548			31			1,688			1,425			18
Retail cost of sales ^(a)		772			1,264			(39	)		2,204			2,126			4
Mark-to-market activities		62			(202	)		131			23			(476	)		105
Other cost of operations		281			283			(1	)		888			826			8

Total cost of operations		1,835			1,893			(3	)		4,803			3,901			23
Depreciation and amortization		210			212			(1	)		620			594			4
Selling, general and administrative		172			182			(5	)		441			396			11
Acquisition-related transaction and integration costs		—			6			(100	)		—			41			(100	)
Development costs		14			12			17			36			34			6

Total operating costs and expenses		2,231			2,305			(3	)		5,900			4,966			19
Gain on sale of assets		—			—			—			23			—			100

Operating income		454			611			(26	)		1,156			1,845			(37	)
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates		16			6			167			41			33			24

Gain on sale of equity method investments		—			—			—			—			128			(100	)
Other income/(expense), net		11			5			120			34			(9	)		478
Interest expense		(169	)		(178	)		(5	)		(469	)		(475	)		(1	)

Total other expense		(142	)		(167	)		(15	)		(394	)		(323	)		22

Income before income taxes		312			444			(30	)		762			1,522			(50	)
Income tax expense		89			166			(46	)		271			614			(56	)

Net Income		223			278			(20	)		491			908			(46	)

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

Net income attributable to NRG Energy, Inc.	$	223		$	278			(20	)	$	492		$	909			(46	)

Business Metrics

Average natural gas price — Henry Hub ($/MMBtu)		4.38			3.15			39	%		4.59			3.80			21	%


(a) Includes realized gains and losses from financially settled transactions.

Management’s discussion of the results of operations for the three months ended September 30, 2010, and 2009:

Wholesale Power Generation

The following is a more detailed discussion of the energy and capacity revenues and generation cost of sales for NRG’s wholesale power generation regions, adjusted to eliminate intersegment activity primarily with Reliant Energy.


	Three months ended September 30, 2010
											Total
											Wholesale
											Power					Consolidated
(In millions except otherwise noted)	Texas		Northeast		South Central		West		Other		Generation		Eliminations			Total

Energy revenue	$	855	$	266	$	115	$	15	$	11	$	1,262	$	(452	)	$	810

Capacity revenue		7		108		61		28		17		221		(5	)		216

Generation cost of sales		374		203		114		5		24		720		—			720

Business Metrics
MWh sold (in thousands)		13,646		3,776		3,458		100
MWh generated (in thousands)		12,995		3,443		3,048		100
Average on-peak market power prices ($/MWh)		48.15		68.32		45.58		39.54


	Three months ended September 30, 2009
											Total
											Wholesale
											Power					Consolidated
(In millions except otherwise noted)	Texas		Northeast		South Central		West		Other		Generation		Eliminations			Total

Energy revenue	$	788	$	241	$	88	$	12	$	13	$	1,142	$	(150	)	$	992

Capacity revenue		50		119		71		33		20		293		(18	)		275

Generation cost of sales		287		114		106		10		31		548		—			548

Business Metrics
MWh sold (in thousands)		13,979		2,508		3,243		289
MWh generated (in thousands)		12,534		2,508		2,727		289
Average on-peak market power prices ($/MWh)		33.59		40.43		29.50		38.79

	Three months ended September 30,
Weather Metrics	Texas		Northeast		South Central		West

2010
CDDs ^(a)		1,620		632		1,280		548
HDDs ^(a)		3		98		19		77
2009
CDDs		1,601		419		952		741
HDDs		5		129		14		43
30 year average
CDDs		1,485		430		997		506
HDDs		5		159		33		108


(a)	National Oceanic and Atmospheric Administration-Climate Prediction Center – A Cooling Degree Day, or CDD, represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. A Heating Degree Day, or 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.

•

Energy revenue — decreased $182 million, on a consolidated basis, during the three months ended September 30, 2010, compared to the same period in 2009. Including intercompany sales to Reliant Energy, energy revenue for Wholesale Power Generation increased $120 million, due to:

	o		Texas — increased by $67 million with a $98 million increase driven by higher energy prices due to an increase in average realized energy price of 13%, offset by a decrease of $30 million driven by 4% lower generation sold. Lower generation was driven by a decrease in gas plant generation as certain units were uneconomic to dispatch, which was offset in part by an increase in baseload generation due to decreased maintenance hours in 2010 and an increase in owned and leased wind farm generation, as the Langford wind facilities began commercial operations in December 2009 and South Trent was acquired in June 2010.

	o		Northeast — increased by $25 million, due to an increase in generation of $85 million, or 37%, offset by a decrease in realized energy prices of $76 million, or 24%. The increased generation was comprised of a 64% increase in oil and gas plant generation and a 30% increase in coal plant generation. The increase in oil and gas plant generation is attributable to higher reliability run hours at the Arthur Kill and the Connecticut plants. The increase in coal plant generation is attributable to higher demand primarily in the western New York and PJM markets. Contract revenues also increased by $29 million due to revenues from new load-serving contracts, while margin on megawatt hours sold from market purchases decreased by $14 million due to the expiration of certain load contracts.

	o		South Central — increased by $27 million due to an increase in contract revenue. Total megawatt hours sold to the region’s contract customers increased 17% reflecting the impact of a new contract with a regional municipality and higher sales to cooperative customers. The new contract resulted in $15 million of the increase and an additional $8 million was due to a fuel pass-through to cooperative customers. The average realized price on contract energy sales in 2010 was $28.10 per megawatt hour compared to $22.83 per megawatt hour in 2009.

•

Capacity revenue — decreased $59 million, on a consolidated basis, during the three months ended September 30, 2010, compared to the same period in 2009:

	o		Texas — decreased by $43 million resulting from a lower proportion of baseload contracts which contain a capacity component. Intercompany capacity revenue to Reliant Energy, which eliminates in consolidation, decreased by $13 million.

	o		Northeast — decreased by $11 million, of which $15 million is due to the expiration of the RMR contracts for the Montville, Middletown and Norwalk plants on May 31, 2010, together with lower volume of capacity sales due to the retirement of the Somerset coal facility starting January 1, 2010. This decrease was offset by an increase in capacity sales in the NYISO market driven in part by the retirement of the New York Power Authority’s Poletti facility in January 2010.

	o		South Central — decreased by $10 million primarily due to the expiration of a capacity agreement with a regional utility.

•

Generation cost of sales — increased $172 million during the three months ended September 30, 2010, compared to the same period in 2009 due to:

	o		Texas — increased $87 million due to higher coal costs of $39 million, an increase of $10 million in costs of purchased energy, higher natural gas costs of $16 million, and higher ancillary services costs of $6 million. Coal costs increased $22 million due to higher transportation charges. Purchased energy costs reflect increased obligations when baseload plants are unavailable and additional purchases for bilateral and toll energy agreements. Natural gas costs increased due to an increase in average natural gas prices of 36%, offset by a decrease of 12% in gas-fired generation.

	o		Northeast — increased $89 million driven by a $35 million increase in natural gas and oil costs, a $28 million increase in purchased energy, and a $26 million increase in coal costs. Natural gas and oil costs increased due to 64% higher generation and 14% higher average natural gas prices. Purchased energy increased due to costs to supply new load contracts which commenced on June 1, 2010. Coal costs increased due to 5% higher average prices and a 30% increase in coal generation related to increased run times in 2010 as discussed above.

Reliant Energy

The following is a detailed discussion of retail revenues and cost of sales for NRG’s Reliant Energy business segment.


	Three months ended September 30,
(In millions except otherwise noted)	2010		2009

Retail Revenues
Mass revenues	$	997	$	1,157
Commercial and Industrial revenues		546		620
Supply management revenues		50		99

Total retail operating revenues ^(a)		1,593		1,876
Retail cost of sales ^(b)		1,239		1,433

Total retail gross margin	$	354	$	443


Business Metrics
Electricity sales volume — GWh
Mass		7,547		7,776
Commercial and Industrial ^(a)		7,179		8,199

Weighted average retail customer count (in thousands, metered locations)
Mass		1,473		1,569
Commercial and Industrial ^(a)		63		68
Retail customer count (in thousands, metered locations)
Mass		1,468		1,552
Commercial and Industrial ^(a)		62		66
Weather Metrics
CDDs ^(c)		1,820		1,760
HDDs ^(c)		—		1


(a)	Includes customers of the Texas General Land Office, for whom the Company provides services.

(b)	Includes intercompany purchases from the Texas region of $467 million and $169 million in 2010 and 2009, respectively.

(c)	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.

	•		Retail gross margin — Reliant Energy’s gross margin of $354 million for the three months ended September 30, 2010, is a decline of $89 million due to 17% lower Mass margins driven by lower unit margins on acquisitions and renewals and 4% lower Mass volumes sold driven by fewer customers. Competition and lower unit margins on acquisitions and renewals could drive lower gross margin in the future.

			The following table reconciles Reliant Energy’s retail gross margin to operating (loss)/income:


	Three months ended September 30,
(In millions)	2010			2009

Total Retail Gross Margin	$	354		$	443
Mark-to-market results on energy supply derivatives		(173	)		217
Contract amortization, net		(23	)		(73	)
Other operating expenses		(145	)		(136	)
Depreciation and amortization		(32	)		(42	)

Operating (Loss)/Income	$	(19	)	$	409

•

Retail operating revenues — decreased by $283 million during the three months ended September 30, 2010, as compared to the same period in 2009 due to:

Mass revenues — decreased by $160 million, with a decrease of $105 million driven by reduced revenue rates due to lower revenue pricing on acquisitions and renewals consistent with competitive offers and a $60 million decrease due to 4% lower volumes, which reflects 0.5% monthly net customer attrition between October 2009 and September 2010 from increased competition. Favorable weather in both periods resulted in 4% higher customer usage in 2010 and 3% in 2009 when compared to ten-year normal weather.

Commercial and Industrial revenue — decreased by $74 million due to 12% lower volumes. The lower volumes were driven by fewer customers due to fewer contract renewals and new customer acquisitions and lower average usage due to a change in Reliant Energy’s customer mix.

•

Retail cost of sales — decreased by $194 million during the three months ended September 30, 2010, as compared to same period in 2009 due to:

Supply costs and financial costs of energy – including intercompany purchases from the Texas region of $467 million and $169 million in 2010 and 2009 respectively, decreased by $182 million. Intercompany purchases include purchases of energy and ancillary services. This decrease was due to an $86 million decrease attributed to 8% lower volumes driven by fewer customers, a $78 million decrease due to 8% lower hedged prices, and favorable impacts of $18 million for out-of-market supply contracts terminated in the fourth quarter of 2009 in conjunction with the CSRA unwind.

Transmission and distribution charges — decreased by $12 million with $24 million due to lower volumes transported and sold to customers in 2010 as compared to 2009 driven by fewer customers in 2010. Partially offsetting this decrease was a $12 million increase in rates billed by CenterPoint Energy for system restoration charges due to the damage caused by Hurricane Ike. These rates were effective December 2009.

Mark-to-market Activities

Mark-to-market activities include economic hedges that did not qualify for cash flow hedge accounting, ineffectiveness on cash flow hedges, and trading activities. Total net mark-to-market results decreased by $20 million during the three months ended September 30, 2010, compared to the same period in 2009.

The breakdown of gains and losses included in operating revenues and operating costs and expenses by region are as follows:


	Three months ended September 30, 2010
	Reliant								South
	Energy			Texas		Northeast			Central			West			Thermal		Elimination^(a)			Total
	(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(1	)	$	20	$	(26	)	$	—		$	—		$	—	$	27		$	20
Reversal of previously recognized unrealized losses on settled positions related to trading activity		—			13		4			3			—			—		—			20
Net unrealized gains/(losses) on open positions related to economic hedges		1			119		(16	)		(19	)		—			—		(107	)		(22	)
Net unrealized gains/(losses) on open positions related to trading activity		—			3		9			(2	)		(1	)		—		—			9

Total mark-to-market gains/(losses) in operating revenues	$	—		$	155	$	(29	)	$	(18	)	$	(1	)	$	—	$	(80	)	$	27


Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(32	)	$	7	$	3		$	4		$	—		$	—	$	(27	)	$	(45	)
Reversal of loss positions acquired as part of the Reliant Energy acquisition as of May 1, 2009		7			—		—			—			—			—		—			7
Net unrealized (losses)/gains on open positions related to economic hedges		(148	)		10		1			6			—			—		107			(24	)

Total mark-to-market (losses)/gains in operating costs and expenses	$	(173	)	$	17	$	4		$	10		$	—		$	—	$	80		$	(62	)


(a)	Represents the elimination of the intercompany activity between the Texas and Reliant Energy regions.


	Three months ended September 30, 2009
	Reliant									South
	Energy			Texas			Northeast			Central			West			Thermal		Elimination^(a)			Total
	(In millions)
Mark-to-market results in operating 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 (losses)/gains 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	)

Total mark-to-market (losses)/gains in operating revenues	$	(1	)	$	(102	)	$	(99	)	$	(25	)	$	(6	)	$	1	$	15		$	(217	)


Mark-to-market results in operating costs and expenses
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 (losses)/gains on open positions related to economic hedges		(21	)		(18	)		2			(16	)		—			—		(15	)		(68	)

Total mark-to-market gains/(losses) in operating costs and expenses	$	218		$	(7	)	$	22		$	(16	)	$	—		$	—	$	(15	)	$	202


(a)	Represents the elimination of the intercompany activity between the Texas and Reliant Energy regions.

Mark-to-market results consist of unrealized gains and losses. The settlement of these transactions is reflected in the same caption as the items being hedged.

For the three months ended September 30, 2010, the $22 million loss in operating revenue from economic hedge positions is primarily driven by a decrease in value of forward purchases and sales of natural gas and electricity due to a decrease in forward power and gas prices. The $24 million loss in operating costs and expenses from economic hedge positions is primarily driven by a decrease in value of forward purchases of natural gas, electricity and fuel due to a decrease in forward power and gas prices. Reliant Energy’s $7 million gain from the roll-off of acquired derivatives consists of loss positions that were acquired as of May 1, 2009, and valued using forward prices on that date. The roll-off amounts were offset by realized losses at the settled prices and higher costs of physical power which are reflected in operating costs and expenses during the same period.

For the three months ended September 30, 2009, the $156 million mark-to-market loss in operating revenue related to a decrease in value in forward sales and purchases of electricity and fuel relating to economic hedges due to a decrease in forward power and gas prices. The $68 million mark-to-market loss in operating costs and expenses related to economic hedges was due to a decrease in forward purchases of electricity and natural gas relating to retail supply, due to a decrease in forward power and gas prices.

In accordance with ASC 815, the following table represents the results of the Company’s financial and physical trading of energy commodities for the three months ended September 30, 2010, and 2009. The unrealized financial and physical trading results are included in the mark-to-market activities above, while the realized financial and physical trading results are included in energy revenue. The Company’s trading activities are subject to limits within the Company’s Risk Management Policy.


	Three months ended September 30,
(In millions)	2010		2009

Trading gains/(losses)
Realized	$	2	$	46
Unrealized		29		(30	)

Total trading gains	$	31	$	16

Other Revenues

Other revenues increased by $49 million during the three months ended September 30, 2010, as compared to the same period in 2009. This increase was driven by $37 million in lower contract amortization and a $5 million increase in ancillary revenue. The lower contract amortization is the result of a $54 million decrease in contract amortization expense for net in-market C&I contracts related to the Reliant Energy acquisition in May 2009, offset by a reduction of $15 million in contract amortization revenue in the Texas region due to the lower volume of contracted energy. Ancillary revenue increased due to higher ancillary services in the Texas region.

Depreciation and Amortization

NRG’s depreciation and amortization expense decreased by $2 million for the three months ended September 30, 2010, compared to the same period in 2009. Depreciation and amortization expense for Reliant Energy decreased by $10 million mainly due to a reduction in amortization expense for customer relationships which are amortized based on expected future cash flows. This decrease was offset by a $5 million increase in depreciation related to the Langford wind facilities, which began commercial operations in December 2009.

Selling, General and Administrative Expenses

Selling, general and administrative expenses decreased by $10 million during the three months ended September 30, 2010, compared to the same period in 2009. Consultant costs decreased by $18 million, $21 million due to the non-recurring costs related to Exelon’s exchange offer and proxy contest efforts incurred in 2009, offset by a $3 million increase in consultant costs for various on-going projects in 2010. In addition, retail bad debt expense decreased $5 million due to decreased revenues and improved customer payments behavior. These decreases were offset by $8 million in funding for the Reliant Energy Charitable Foundation in 2010.

Acquisition-related Transaction and Integration Costs

NRG incurred Reliant Energy acquisition-related transaction and integration costs of $6 million for the three months ended September 30, 2009. These integration efforts were completed by the end of 2009.

Equity in Earnings of Unconsolidated Affiliates

NRG’s equity earnings from unconsolidated affiliates increased by $10 million during the three months ended September 30, 2010, compared to the same period in 2009, primarily from an increase in equity earnings from Sherbino resulting from an increase in the fair value of a hedge.

Interest Expense

NRG’s interest expense decreased by $9 million during the three months ended September 30, 2010, compared to the same period in 2009 due to the following:


(In millions)

(Decrease)/increase in interest expense
Decrease in fees incurred on the CSRA facility	$	(14	)
Decrease due to settlement of the CSF Debt in 2009 and early 2010		(10	)
Increase for Term Loan Facility due to amendment and extension of facility in June 2010		5
Increase for 2020 Senior Notes issued in August 2010		10

Total	$	(9	)

Income Tax Expense

NRG’s income tax expense decreased by $77 million during the three months ended September 30, 2010, compared to the same period in 2009. The decrease in income tax expense was primarily due to a decrease in income. The effective tax rate was 28.5% and 37.4% for the three months ended September 30, 2010, and 2009, respectively.

Management’s discussion of the results of operations for the nine months ended September 30, 2010, and 2009:

Wholesale Power Generation

The following is a more detailed discussion of the energy and capacity revenues and generation cost of sales for NRG’s wholesale power generation regions adjusted to eliminate intersegment activity primarily with Reliant Energy.


	Nine months ended September 30, 2010
											Total
											Wholesale
											Power					Consolidated
(In millions except otherwise noted)	Texas		Northeast		South Central		West		Other		Generation		Eliminations			Total

Energy revenue	$	2,226	$	580	$	297	$	26	$	34	$	3,163	$	(972	)	$	2,191

Capacity revenue		19		311		176		81		53		640		(12	)		628

Generation cost of sales		897		395		311		11		74		1,688		—			1,688

Business Metrics
MWh sold (in thousands)		36,489		8,509		9,858		197
MWh generated (in thousands)		34,866		7,520		8,056		197
Average on-peak market power prices ($/MWh)		43.10		58.41		42.62		40.94


	Nine months ended September 30, 2009
											Total
											Wholesale
											Power					Consolidated
(In millions except otherwise noted)	Texas		Northeast		South Central		West		Other		Generation		Eliminations			Total

Energy revenue	$	2,126	$	656	$	276	$	16	$	37	$	3,111	$	(206	)	$	2,905

Capacity revenue		144		316		204		93		58		815		(29	)		786

Generation cost of sales		719		309		297		17		83		1,425		—			1,425

Business Metrics
MWh sold (in thousands)		36,485		6,779		9,204		365
MWh generated (in thousands)		34,527		6,779		7,819		365
Average on-peak market power prices ($/MWh)		34.91		46.13		33.00		37.46

	Nine months ended September 30,
Weather Metrics	Texas		Northeast		South Central		West

2010
CDDs		2,646		847		1,969		623
HDDs		1,467		3,545		2,442		2,081
2009
CDDs		2,709		496		1,540		885
HDDs		1,008		4,126		2,108		1,923
30 year average
CDD		2,433		534		1,486		663
HDD		1,210		4,093		2,227		2,083

•

Energy revenue — decreased $714 million, on a consolidated basis, during the nine months ended September 30, 2010, compared to the same period in 2009. Including intercompany sales to Reliant Energy, energy revenue for Wholesale Power Generation increased $52 million, due to:

	o		Texas — increased by $100 million, with $99 million driven by 5% higher average realized energy prices. Generation increased by less than 1%, driven by an increase in owned wind farm generation as Langford wind facilities began commercial operations in December 2009 and South Trent was acquired in June 2010, offset by a 7% decrease in nuclear plant generation due to planned maintenance outages.

	o		South Central — increased by $21 million due to a $58 million increase in contract revenue offset by a $37 million decrease in merchant energy revenues. The increase in contract revenue was driven by $31 million attributable to the region’s cooperative customers and $27 million due to a new contract with a regional municipality. Merchant energy revenue decreased as average realized prices decreased by 22% from 2009, resulting in a decrease in revenue of $20 million, and volume decreases resulted in a decrease in revenue of $17 million.

	o		West — increased by $10 million due to incremental revenue of $5 million from the commencement of operations at the Blythe solar facility and increase in merchant energy prices in 2010 compared to 2009, offset in part by a 12% decrease in generation.

	o		Northeast — decreased by $76 million, driven by a decrease in realized energy prices of $157 million, or 23% and a decrease of $28 million of margin on megawatt hours sold from market purchase for certain load contracts which expired in May 2009 and 2010. These decreases were offset by an increase of $68 million driven by an increase in generation and an increase of $37 million driven by new load-serving contracts, which commenced June 1, 2010. Generation increased by 11%, driven by a 22% increase in oil and gas plant generation and a 9% increase in coal plant generation. The increase in oil and gas plant generation is attributable to higher reliability run hours at the Arthur Kill and Connecticut plants offset by both planned and forced outages and reserve shutdowns at the Arthur Kill, Middletown and Oswego plants in 2010. The increase in coal plant generation was primarily at the Indian River plant due to higher summer temperatures in 2010 and a major turbine overhaul in prior year as well as prior year planned and forced outages at Dunkirk units 3 and 4.

•

Capacity revenue — decreased $158 million, on a consolidated basis, during the nine months ended September 30, 2010, compared to the same period in 2009:

	o		Texas — decreased by $125 million due to a lower proportion of baseload contracts which contain a capacity component. Intercompany capacity revenue to Reliant Energy, which eliminate in consolidation, decreased by $17 million.

	o		South Central — decreased by $28 million due to the expiration of a capacity agreement with a regional utility.

	o		West — decreased by $12 million due to reduced resource adequacy and call option contract sales at El Segundo in 2010 as compared to 2009.

	o		Northeast — decreased by $5 million, due to a $28 million decrease in revenue from NEPOOL capacity driven by the expiration of RMR contracts for the Montville, Middletown and Norwalk plants in 2010, together with lower volume of capacity sales due to the retirement of the Somerset coal facility starting January 1, 2010. This decrease was offset by a $24 million increase in capacity revenue in the NYISO and PJM markets driven in part by the retirement of the New York Power Authority’s Poletti facility in January 2010.

•

Generation cost of sales — increased $263 million during the nine months ended September 30, 2010, compared to the same period in 2009 due to:

	o		Texas — increased $178 million due to higher coal and natural gas costs, an increase in purchased energy, and higher ancillary services costs. Coal costs increased by $68 million due to a $52 million increase in transportation cost and a $16 million increase due to higher prices. Natural gas costs increased $38 million, reflecting a 27% increase in average natural gas prices and a 1% increase in gas-fired generation. There was an increase of $24 million in costs of purchased energy for increased obligations when baseload plants are unavailable and additional purchases for bilateral and toll energy agreements. Ancillary service costs increased by $23 million due to an increase in purchased ancillary costs incurred to meet contract obligations. In addition, there was an increase of $10 million in emission credit expense reflecting an increase in SO₂credits required by the amended CAIR rules as compared to the same period in 2009.

	o		Northeast — increased by $86 million due to a $36 million increase in purchased energy, a $25 million increase in coal costs due to a 3% increase in average prices, a 9% increase in coal generation as previously discussed, and an increase in natural gas and oil costs of $30 million due to a 6% increase in average prices and a 22% increase in generation. These increases were offset by a $5 million decrease in financial cost of energy from a decrease in the value of settled oil and natural gas positions rolling-off during 2010.

	o		South Central — increased by $14 million due to a $10 million increase in purchased energy and an increase of $4 million in transmission costs due to higher volumes in and out of the region.

Reliant Energy

The following is a detailed discussion of retail revenues and cost of sales for NRG’s Reliant Energy business segment.


	Nine months ended		Four months ended		Five months ended		Five months ended
(In millions except otherwise noted)	September 30, 2010		April 30, 2010		September 30, 2010		September 30, 2009^(d)

Retail Revenues
Mass revenues	$	2,518	$	903	$	1,615	$	1,918
Commercial and Industrial revenues		1,537		640		897		1,057
Supply management revenues		124		56		68		151

Total retail operating revenues ^(a)		4,179		1,599		2,580		3,126
Retail cost of sales ^(b)		3,224		1,232		1,992		2,363

Total retail gross margin		955		367		588		763

Business Metrics
Electricity sales volume — GWh
Mass		18,093		6,089		12,004		12,627
Commercial and Industrial ^(a)		20,071		8,268		11,803		13,780

Weighted average retail customers count (in thousands, metered locations)
Mass		1,500		1,519		1,483		1,582
Commercial and Industrial ^(a)		63		64		63		69
Retail customers count (in thousands, metered locations)
Mass		1,468		1,513		1,468		1,552
Commercial and Industrial ^(a)		62		63		62		66
Weather Metrics
CDDs ^(c)		3,000		166		2,834		2,731
HDDs ^(c)		1,268		1,267		1		2


(a)	Includes customers of the Texas General Land Office, for whom the Company provides services.

(b)	Includes intercompany purchases from the Texas region of $1,020 million, $293 million, $727 million and $237 million, respectively.

(c)	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.

(d)	For the period ended May 1, 2009, to September 30, 2009.

	•		Retail gross margin — excluding gross margin of $367 million for the first four months of 2010, Reliant Energy’s gross margin decreased $175 million for the five months ended September 30, 2010, due to 19% lower Mass margins driven by lower unit margins on acquisitions and renewals and price reductions for certain customer segments and 5% lower Mass volumes sold driven by fewer customers. Competition and lower unit margins on acquisitions and renewals could drive lower gross margin in the future.

			The following table reconciles Reliant Energy’s retail gross margin to operating income/(loss):


	Nine months ended			Four months ended			Five months ended			Five months ended
(In millions)	September 30, 2010			April 30, 2010			September 30, 2010			September 30, 2009

Total Retail gross margin	$	955		$	367		$	588		$	763
Mark-to-market results on energy supply derivatives		(298	)		(249	)		(49	)		520
Contract amortization, net		(132	)		(79	)		(53	)		(135	)
Other operating expenses		(361	)		(140	)		(221	)		(226	)
Depreciation and amortization		(91	)		(39	)		(52	)		(85	)

Operating Income/(Loss)	$	73		$	(140	)	$	213		$	837

•

Retail operating revenues — increased by $1,053 million during the nine months ended September 30, 2010, as compared to the five months ended September 30, 2009, or decreased by $546 million excluding the four months ended April 30, 2010, due to:

Mass revenues — excluding revenues of $903 million for the first four months of 2010, Mass revenues decreased by $303 million for the five months ended September 30, 2010, with $181 million due to lower revenue rates driven by lower revenue pricing on acquisitions and renewals consistent with competitive offers and price reductions for certain customer segments. In addition, $129 million was due to 5% lower volumes which reflects 0.5% monthly net customer attrition between October 2009 and September 2010 from increased competition. Favorable weather in both periods resulted in 6% higher customer usage in 2010 and 4% in 2009 when compared to ten-year normal weather.

Commercial and Industrial revenue — excluding revenues of $640 million for the first four months of 2010, C&I revenues decreased by $160 million for the five months ended September 30, 2010, compared to the same time period in 2009. This decrease was due to 14% lower volumes driven by fewer customers due to fewer contract renewals and new customer acquisitions.

•

Retail cost of sales — increased by $861 million for the nine months ended September 30, 2010, as compared to the five months ended September 30, 2009, or decreased by $371 million excluding the four months ended April 30, 2010, due to:

Supply costs and financial costs of energy — including intercompany purchases from the Texas region of $1,020 million and $237 million in 2010 and 2009 respectively, and excluding supply costs of $839 million for the first four months of 2010, supply costs decreased by $334 million for the five months ended September 30, 2010. This decrease is due to a $162 million decrease attributed to 9% lower hedged prices, a $138 million decrease due to 10% lower volumes driven by fewer customers, and favorable impacts of $31 million for out-of-market supply contracts terminated in the fourth quarter of 2009 in conjunction with the CSRA unwind. The terminated contract value for January through April 2010 was $34 million.

Transmission and distribution charges — excluding transmission and distribution costs of $393 million for the first four months of 2010, transmission and distribution charges decreased by $37 million for the five months ended September 30, 2010, with $59 million due to lower volumes transported and sold to customers in 2010 versus 2009. The lower volumes were driven by fewer customers in 2010. Partially offsetting this decrease was a $22 million increase in rates billed by CenterPoint Energy for system restoration charges due to the damage caused by Hurricane Ike. These rates were effective December 2009.

Mark-to-market Activities

Mark-to-market activities include economic hedges that did not qualify for cash flow hedge accounting, ineffectiveness on cash flow hedges, and trading activities. Total net mark-to-market results decreased by $386 million during the nine months ended September 30, 2010, compared to the same period in 2009.

The breakdown of gains and losses included in operating revenues and operating costs and expenses by region are as follows:


	Nine months ended September 30, 2010
	Reliant									South
	Energy			Texas			Northeast			Central			West		Thermal			Elimination^(a)			Total
	(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(1	)	$	(33	)	$	(84	)	$	1		$	—	$	(2	)	$	18		$	(101	)
Reversal of previously recognized unrealized losses on settled positions related to trading activity		—			33			7			6			—		—			—			46
Net unrealized gains/(losses) on open positions related to economic hedges		1			275			(14	)		(41	)		1		—			(186	)		36
Net unrealized gains on open positions related to trading activity		—			10			17			4			1		—			—			32

Total mark-to-market gains/(losses) in operating revenues	$	—		$	285		$	(74	)	$	(30	)	$	2	$	(2	)	$	(168	)	$	13


Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(52	)	$	30		$	12		$	13		$	—	$	—		$	(18	)	$	(15	)
Reversal of loss positions acquired as part of the Reliant Energy acquisition as of May 1, 2009		157			—			—			—			—		—			—			157
Net unrealized (losses)/gains on open positions related to economic hedges		(403	)		27			8			17			—		—			186			(165	)

Mark-to-market (losses)/gains in operating costs and expenses	$	(298	)	$	57		$	20		$	30		$	—	$	—		$	168		$	(23	)


(a)	Represents the elimination of the intercompany activity between the Texas and Reliant Energy regions.


	Nine months ended September 30, 2009
	Reliant									South
	Energy^(a)			Texas			Northeast			Central			West			Thermal			Elimination^(b)			Total
	(In millions)
Mark-to-market results in operating 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 (losses)/gains on open positions related to trading activity		—			(3	)		6			(4	)		—			—			—			(1	)

Total mark-to-market (losses)/gains in operating revenues	$	(1	)	$	(36	)	$	(22	)	$	(55	)	$	—		$	—		$	14		$	(100	)


Mark-to-market results in operating costs and expenses
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	)

Total mark-to-market gains/(losses) in operating costs and expenses	$	521		$	(48	)	$	43		$	(26	)	$	—		$	—		$	(14	)	$	476


(a)	Reliant Energy results are for the period May 1, 2009, to September 30, 2009.

(b)	Represents the elimination of the intercompany activity between the Texas and Reliant Energy regions.

Mark-to-market results consist of unrealized gains and losses. The settlement of these transactions is reflected in the same caption as the items being hedged.

For the nine months ended September 30, 2010, the $36 million gain in operating revenue from economic hedge positions is primarily driven by an increase in value of forward sales and purchases of natural gas and electricity due to a decrease in forward power and gas prices. The $165 million loss in operating costs and expenses from economic hedge positions is primarily driven by a decrease in value of forward purchases of natural gas, electricity and fuel due to a decrease in forward power and gas prices. Reliant Energy’s $157 million gain from the roll-off of acquired derivatives consists of loss positions that were acquired as of May 1, 2009, and valued using forward prices on that date. The roll-off amounts were offset by realized losses at the settled prices and higher costs of physical power which are reflected in operating costs and expenses during the same period.

In accordance with ASC 815, the following table represents the results of the Company’s financial and physical trading of energy commodities for the nine months ended September 30, 2010, and 2009. The unrealized financial and physical trading results are included in the mark-to-market activities above, while the realized financial and physical trading results are included in energy revenue. The Company’s trading activities are subject to limits within the Company’s Risk Management Policy.


	Nine months ended September 30,
(In millions)	2010			2009

Trading gains/(losses)
Realized	$	(22	)	$	142
Unrealized		78			(126	)

Total trading gains/(losses)	$	56		$	16

Other Revenues

Other revenues decreased by $72 million during the nine months ended September 30, 2010, as compared to the same period in 2009.

This decrease was driven by $45 million in lower contract amortization revenue and a $25 million decrease in miscellaneous revenue as compared to 2009. The lower contract amortization revenue is the result of a reduction of $43 million in the Texas region due to the lower volume of contracted energy. The decrease in miscellaneous revenue is due to a $31 million non-cash gain related to the settlement of a pre-existing in-the-money contract with Reliant Energy that was recognized in 2009.

Other Operating Costs

Other operating costs increased $62 million during the nine months ended September 30, 2010, compared to the same period in 2009, due to:

	•		Reliant Energy — increased due to the additional four months of other operating costs of $49 million included in 2010.

	•		Operations and maintenance expense — increased by $35 million due to the following:

	o		Texas — increased $19 million due to maintenance work during planned baseload outages.

	o		South Central — increased $17 million as the scope and duration of planned maintenance work at the region’s coal facility was greater in 2010 than in the same period in 2009.

	o		Northeast — increased $5 million due to $11 million in charges relating to the write-off of previously capitalized costs on the Indian River Unit 3 back end controls project together with associated cancellation penalties and write-offs for other asset retirements of $8 million. These increases were offset by decreases in normal and major maintenance of $16 million due to lower spending at the Indian River and Arthur Kill plants, which had major outage work performed in the second quarter of 2009.

These increases were offset by:

Reliant Energy — decreased $10 million due to lower spending for information technology consulting and call center operations.

•

Property and other taxes — decreased $17 million due to the following:

	o		Northeast — decreased $6 million due to a charge in June 2009 to reflect changes in Empire Zone regulations that eliminated the Oswego plant’s ability to continue participation in the Empire Zone program.

	o		Reliant Energy — decreased $6 million due to a decrease in gross receipts tax reflective of a corresponding decrease in revenues.

	o		Texas — decreased $4 million due to a sales and use tax audit refund and lower property taxes.

Depreciation and Amortization

NRG’s depreciation and amortization expense increased by $26 million during the nine months ended September 30, 2010, compared to the same period in 2009. Reliant Energy’s depreciation and amortization expense increased by $6 million due to the additional four months of depreciation and amortization expense of $39 million included in 2010 offset by a decrease of amortization expense of $35 million during the five months ended September 30, 2010 as compared to the same period in 2009, which related to the front-loading of amortization expense in the earlier years. An additional increase of $16 million was due to depreciation on the baghouse projects in western New York and additional depreciation at the Cedar Bayou plant, the Langford wind facilities and the Blythe solar facility. Cedar Bayou began commercial operation in June 2009 and the Langford wind facilities began commercial operation in December 2009.

Selling, General and Administrative Expenses

Selling, general and administrative expenses increased by $45 million during the nine months ended September 30, 2010, compared to the same period in 2009. The increase was due to:

•

Retail selling, general and administrative expense — increased by $69 million due to the additional four months of expense of $73 million and $8 million in funding for the Reliant Energy Charitable Foundation. These increases were offset by a decrease in bad debt expense of $5 million due to decreased revenues and improved customer payment behavior.

This increase was offset by:

•

Consultant costs — decreased by $25 million, including $31 million due to non-recurring costs related to Exelon’s exchange offer and proxy contest efforts incurred in 2009, offset by an increase of $6 million in consultant costs for various on-going projects in 2010.

Acquisition-related Transaction and Integration Costs

NRG incurred Reliant Energy acquisition-related transaction and integration costs of $41 million for 2009. These integration efforts were completed by the end of 2009.

Gain on Sale of Assets

On January 11, 2010, NRG sold Padoma to Enel, recognizing a gain on sale of $23 million.

Equity in Earnings of Unconsolidated Affiliates

NRG’s equity earnings from unconsolidated affiliates increased by $8 million during the nine months ended September 30, 2010, compared to the same period in 2009. Equity earnings increased by $21 million from Sherbino and $5 million from Gladstone. In 2009, NRG recognized $15 million from MIBRAG, which was sold in June 2009.

Gain on Sale of Equity Method Investments

NRG’s gain on sale of equity method investments in 2009 represents a $128 million gain on the sale of NRG’s 50% ownership interest in MIBRAG.

Other Income/(Expense), Net

NRG’s other income/(expense), net increased $43 million during the nine months ended September 30, 2010, compared to the same period in 2009. The 2010 amount includes $5 million and $9 million of unrealized and realized foreign exchange gains, respectively. The 2009 amount includes a $24 million loss on a forward contract for foreign currency executed to hedge the sale proceeds from the MIBRAG sale in 2009.

Interest Expense

NRG’s interest expense decreased $6 million during the nine months ended September 30, 2010, compared to the same period in 2009 due to the following:


(In millions)

(Decrease)/Increase in interest expense
Decrease in fees incurred on the CSRA facility	$	(24	)
Decrease due to settlement of the CSF Debt in 2009 and early 2010		(27	)
Decrease for Term Loan balance reduced in 2010		(7	)
Increase for 2019 Senior Notes issued in June 2009		25
Decrease in capitalized interest		21
Increase for 2020 Senior Notes issued in August 2010		10
Other		(4	)

Total	$	(6	)

Income Tax Expense

NRG’s income tax expense decreased by $343 million during the nine months ended September 30, 2010, compared to the same period in 2009. The decrease in income tax expense was primarily due to a decrease in income. The effective tax rate was 35.6% and 40.3% for the nine months ended September 30, 2010, and 2009, respectively.

Liquidity and Capital Resources

Liquidity Position

As of September 30, 2010, and December 31, 2009, NRG’s liquidity, excluding collateral received, was approximately $4.8 billion and $3.8 billion, respectively, comprised of the following:


	September 30,			December 31,
(In millions)	2010			2009

Cash and cash equivalents	$	3,447		$	2,304
Funds deposited by counterparties		457			177
Restricted cash		19			2

Total cash		3,923			2,483
Funded Letter of Credit Facility availability		450			583
Revolving Credit Facility availability		839			905

Total liquidity		5,212			3,971
Less: Funds deposited as collateral by hedge counterparties		(457	)		(177	)

Total liquidity, excluding collateral received	$	4,755		$	3,794

For the nine months ended September 30, 2010, total liquidity, excluding collateral received, increased by $961 million due to higher cash and cash equivalent balances of $1,143 million offset by decreased availability of the Funded Letter of Credit Facility of $133 million and decreased availability of $66 million in the Revolving Credit Facility. The higher cash and cash equivalents was primarily due to net proceeds from the issuance of the $1.1 billion aggregate principal amount of 2020 Senior Notes in August 2010. The Revolving Credit Facility availability decrease was due to a decrease in capacity of $125 million as a result of the refinancing of the Senior Credit Facility, offset by an increase of $59 million due to the cancellation in February 2010 of the letter of credit issued in support of the Dunkirk bonds, as described further in Note 8, Long-Term Debt to this Form 10-Q. Changes in cash and cash equivalent balances are further discussed below under the heading Cash Flow Discussion. Cash and cash equivalents and funds deposited by counterparties at September 30, 2010, were predominantly held in money market funds invested in treasury securities, treasury repurchase agreements or government agency debt. The Company anticipates utilizing $2.2 billion of its cash and cash equivalents to fund the pending acquisitions of the Dynegy Plants, Cottonwood and Green Mountain, as discussed in Note 4, Business Acquisitions and Dispositions, to this Form 10-Q.

The line item “Funds deposited by counterparties” represents the amounts that are held by NRG as a result of collateral posting obligations from the Company’s counterparties due to positions in the Company’s 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.

Management believes that the Company’s liquidity position and cash flows from operations will be adequate to finance operating and maintenance capital expenditures 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 LIQUIDITY

The principal sources of liquidity for NRG’s future operating and capital expenditures are expected to be derived from new and existing financing arrangements, existing cash on hand and cash flows from operations. As described in Note 8, Long-Term Debt, to this Form 10-Q and Note 12 – Debt and Capital Leases, to the Company’s 2009 Form 10-K, the Company’s financing arrangements consist mainly of the Senior Credit Facility, the TANE Facility, the Senior Notes, project-related financings and the GenConn Energy LLC related financings.

In addition, 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, 2010, 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 baseload capacity under the first and second lien structure as of September 30, 2010:


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

In MW ^(b)		3,204			2,220			1,371			718
As a percentage of total net baseload capacity ^(c)		47	%		33	%		20	%		11	%


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

(b)	2010 MW value consists of November through December positions only.

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

USES OF LIQUIDITY

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, 2010, commercial operations had total cash collateral outstanding of $477 million, and $618 million outstanding in letters of credit to third parties primarily to support its commercial activities for both wholesale and retail transactions (includes a $60 million letter of credit relating to deposits at the PUCT that covers outstanding customer deposits and residential advance payments). As of September 30, 2010, total collateral held from counterparties was $457 million in cash and $13 million of letters of credit.

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

Capital Expenditures

The following tables summarize the Company’s capital expenditures for the nine months ended September 30, 2010, and the estimated capital expenditure and repowering investments forecast for the remainder of 2010.

RepoweringNRG capital expenditures for nuclear development — RepoweringNRG project capital expenditures related to the development of STP Units 3 and 4 in Texas are as follows:


	Nine months ended			Estimated amounts for
(In millions)	September 30, 2010			the remainder of 2010

Capital expenditures, including accruals	$	413		$	91
Adjustments to reconcile to capital expenditures paid:
Accrued liabilities related to CPS settlement		(88	)		—
Net (increase) decrease in NINA’s accounts payable		(109	)		138
Projected draws on vendor credit facilities		—			(228	)

Cash used for capital expenditures	$	216		$	1

A portion of these capital expenditures were funded by NRG equity contributions into NINA of $173 million for the nine month period, which were used both for capital expenditures and development expenses. NRG expects to make another $5 million contribution into NINA in the fourth quarter of 2010. Excluding the accrued liabilities related to the CPS settlement, NINA has funded or anticipates funding the remaining capital expenditures from sources other than NRG, including draws on the TANE Facility and equity contributions from Toshiba and its affiliates. See Note 15, Commitments and Contingencies, to this Form 10-Q for further discussion.

Other segment capital expenditures — capital expenditures, including accruals, for maintenance, environmental and RepoweringNRG other than nuclear development are as follows:


(In millions)	Maintenance		Environmental		Repowering		Total

Northeast	$	9	$	135	$	1	$	145
Texas		58		—		—		58
South Central		10		—		—		10
West		5		—		12		17
Reliant Energy		7		—		—		7
Other		39		—		16		55

Total for the nine months ended September 30, 2010	$	128	$	135	$	29	$	292

Estimated capital expenditures for the remainder of 2010	$	100	$	58	$	171	$	329

For the nine months ended September 30, 2010, the Company’s maintenance capital expenditures included $18 million in nuclear fuel expenditures related to STP Units 1 and 2. In addition, $123 million of environmental capital expenditures for the 2010 year-to-date period relate to a project to install selective catalytic reduction systems, scrubbers and fabric filters on Indian River Unit 4 with an expected in-service date of year-end 2011.

Loans to affiliates — The equity portion of construction costs for GenConn is funded through the EBLs of NRG Connecticut Peaking and The United Illuminating Company, or United Illuminating. These funds are made available to GenConn through interest bearing promissory notes that convert to equity upon repayment of the EBL loans by NRG Connecticut Peaking and United Illuminating. On September 29, 2010, the Devon project reached commercial operations in accordance with the financing documents. Accordingly, NRG repaid the Devon portion of the EBL, and converted $56 million of the promissory note to equity. As of September 30, 2010, there was $62 million 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 2014 to meet NRG’s environmental commitments will be approximately $0.9 billion. These capital expenditures, in general, are related to installation of particulate, SO₂, NO_x, and mercury controls to comply with federal and state air quality rules and consent orders, as well as installation of “Best Technology Available” under the Phase II 316(b) Rule. NRG continues to explore cost effective alternatives that can achieve desired results. While this estimate reflects schedules and controls to meet anticipated reduction requirements, the full impact on the scope and timing of environmental retrofits cannot be determined until issuance of final rules by the U.S. EPA.

This estimate reflects the recent announcement to retrofit only Unit 4 at the Indian River Generating Station and shifts in the timing of other projects to reflect anticipated issuance dates for revised regulations.

NRG’s current contracts with the Company’s rural electrical customers in the South Central region allow for recovery of a portion of the regions’ capital costs once in operation, along with a capital return incurred by complying with new laws, including interest over the asset life of the required expenditures. The actual recoveries will depend, among other things, on the timing of the completion of the capital project and the remaining duration of the contracts.

Reliant Energy Customer Deposits

Revisions in the PUCT rules required that NRG keep a segregated account, or that the Company post a fully collateralized letter of credit on or before May 21, 2010, to cover outstanding customer deposits and residential advance payments. The Company filed an amendment to its Retail Electric Provider certificate in the first quarter of 2010, which was approved by the PUCT, and posted a letter of credit to satisfy the rule changes. The amount of deposits subject to segregation as of September 30, 2010, was approximately $53 million.

Cash Flow Discussion

The following table reflects the changes in cash flows for the comparative years.


(In millions)
Nine months ended September 30,	2010			2009			Change

Net cash provided by operating activities	$	1,141		$	1,280		$	(139	)
Net cash used by investing activities		(570	)		(727	)		157
Net cash provided by financing activities		575			200			375

Net Cash Provided By Operating Activities

Changes to net cash provided by operating activities were driven by:

	•		Lower cash flows from wholesale power generation — The Company’s cash flow from operating activities excluding Reliant Energy was lower by $414 million due to a $250 million decrease in operating income adjusted for non-cash charges, a $131 million decrease related to changes in working capital, and a $33 million decrease in net collateral deposits paid and option premiums paid and collected.

	•		Cash generated by Reliant Energy — Reliant Energy contributed approximately $648 million to the Company’s consolidated cash flow from operating activities for the nine months ended September 30, 2010, compared with $373 million for the five months ended September 30, 2009.

Net Cash Used By Investing Activities

Changes to net cash used by investing activities were driven by:

	•		Cash for acquisitions — During 2010, the Company paid $142 million, primarily for the acquisitions of Northwind Phoenix and South Trent. During 2009, the Company paid $356 million, of which $345 million was for the acquisition of Reliant Energy. See Note 4, Business Acquisitions and Dispositions, to this Form 10-Q for a more complete description of these acquisitions.

	•		Proceeds from renewable energy grants — During 2010, the Company received $102 million of federal cash grants for the Blythe solar and Langford wind facilities.

	•		Capital expenditures and loans to affiliates — NRG’s capital expenditures decreased by $70 million due to decreased spending on maintenance and RepoweringNRG. Loans to affiliates reflects a net increase in cash of $46 million in 2010 as compared to 2009.

	•		Proceeds from sale of assets — Net proceeds increased by $24 million in 2010 as compared to 2009 due to the sale of Padoma in January 2010.

	•		Proceeds from sale of equity method investment — Investing activities in 2009 reflect the sale of MIBRAG in June 2009 for net proceeds of $284 million.

	•		Other — Investing activities in 2010 reflect $16 million invested in equity method investees, including a partnership with Eurus Energy to develop solar projects.

Net Cash Provided By Financing Activities

Changes in net cash provided by financing activities were driven by:

•		Increase in issuance of debt — During 2010, the Company issued $1.2 billion under new debt facilities and $22 million under existing debt facilities. The new debt facilities consist of $1.1 billion 2020 Senior Notes, $100 million by NRG Thermal and $30 million by Blythe. During 2009, the Company received $25 million from the initial draw under the Reliant Energy working capital facility, $38 million from the Dunkirk bonds, $88 million in GenConn financings and $688 million in gross proceeds from the 2019 Senior Notes.

•		Increase in term loan and other facility payments — In 2010, the Company paid down $247 million of its Term Loan Facility, including the payment of excess cash flow, as discussed above under Debt Service Obligations. In addition, NRG Connecticut Peaking repaid the $55 million portion of the EBL used to fund the Devon project and NINA paid $20 million under its revolving credit facility. In 2009, the Company paid down $221 million of its Term Loan Facility.

•		Repayment of CSF I Debt — During 2010, the Company paid $190 million in principal to early settle the CSF I Debt.

•		Net receipt from acquired derivatives that include financing elements — In 2010, the Company received a net of $58 million for the settlement of gas swaps compared with a payment of $140 million for 2009 for the settlement of gas swaps related to Reliant Energy and Texas Genco.

•		Share repurchases — During 2010, the Company repurchased $180 million of NRG common stock as compared to $250 million in 2009.

•		Increase in deferred financing costs — During 2010, deferred financing costs primarily consist of fees paid as a result of the 2020 Senior Notes and the amendment and extension of the Senior Credit Facility. During 2009, deferred financing costs were lower, and related to the Reliant Energy CSRA, the 2019 Senior Notes, the Dunkirk bonds and the Reliant Energy working capital facility.

•		Decrease in preferred stock dividends — During 2010, dividend payments on preferred stock decreased by $20 million as compared to the same period in 2009 due to the conversion of the 5.75% Preferred Stock in 2009 and the conversion of the 4% Preferred Stock, which was completed in January 2010.

NOLs, Deferred Tax Assets and Uncertain Tax Position Implications, under ASC-740, Income Taxes, or ASC 740

As of September 30, 2010, the Company had generated total domestic pre-tax book income of $711 million and foreign pre-tax book income of $51 million. The Company has net operating losses for tax return purposes available to offset taxable income in the current period. In addition, NRG has cumulative foreign NOL carryforwards of $271 million, of which $82 million will expire starting in 2011 through 2018 and of which $189 million do not have an expiration date.

In addition to these amounts, the Company has $640 million of tax effected uncertain tax benefits which relate primarily to net operating losses for tax return purposes but have been classified as capital loss carryforwards for financial statement purposes and for which a full valuation allowance has been established. As a result of the Company’s tax position, and based on current forecasts, NRG anticipates income tax payments, primarily due to foreign, state and local jurisdictions, of up to $25 million in 2010.

However, as the position remains uncertain for the $640 million of tax effected uncertain tax benefits, the Company has recorded a non-current tax liability of $557 million and may accrue the remaining balance as an increase to non-current liabilities until final resolution with the related taxing authority. The $557 million non-current tax liability for uncertain tax benefits is primarily due to taxable earnings for which there are no NOLs available to offset for financial statement purposes and interest.

The examination by the Internal Revenue Service for the years 2004 through 2006 is currently in Joint Committee review and is not considered effectively settled in accordance with ASC 740. The Company anticipates conclusion of the audit by March 31, 2011. Upon effective settlement of the audit the result may be a reduction of the liability for uncertain tax benefits. The Company continues to be under examination for various state jurisdictions for multiple years.

New and On-going Company Initiatives, Development Projects and Acquisitions

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 2010 FORNRG goal is 65 basis points improvement, which corresponds to approximately $98 million in cash flows. The goal is inclusive of benefits created in 2009 and new project benefits reported in 2010. As of the third quarter 2010, the Company has delivered a 55 basis point improvement in ROIC, which is equivalent to approximately $83 million in cash flows under the FORNRG program. During the fourth quarter of 2010, the Company expects to progress further toward the program goal of 100 basis point ROIC improvement by 2012.

RepoweringNRG Update

NRG has several projects in varying stages of development. The Company’s development projects are generally subject to certain conditions, milestones, and other factors that may result in the Company’s decision to no longer pursue the development of these projects. Projects that have achieved a significant milestone, financing, or other material developments are more fully described in the Company’s 2009 Form 10-K and this Quarterly Report on Form 10-Q.

Air permitting litigation unrelated to the El Segundo project had previously delayed receipt of certain required permits, including an air permit, which prevented the El Segundo project from meeting its original completion date of June 2011 under the project PPA. However, legislation enacted on January 1, 2010, has allowed the affected air district to issue air permits like El Segundo’s. A revised draft air permit was issued in April 2010 by the South Coast Air Quality Management District, or SCAQMD, allowing the project permitting to proceed. On June 30, 2010, the California Energy Commission approved the construction permit, and the Company received the final air permit by SCAQMD on July 13, 2010. The Company has executed an amendment to the PPA with the power purchaser which includes a revised commercial operation date of August 1, 2013. The amended PPA was approved by the CPUC on October 28, 2010, which after 30 days becomes final and not subject to further appeal.

On March 9, 2010, NRG was selected by the U.S. DOE to negotiate to receive up to $167 million, including funding from the American Recovery and Reinvestment Act, to build a 60 MW post-combustion carbon capture demonstration unit at NRG’s WA Parish plant southwest of Houston with use of the captured carbon in enhanced oil recovery in adjacent oil fields. The proposed project was submitted under the Clean Coal Power Initiative Program, or CCPI, a cost-shared collaboration between the federal government and private industry to demonstrate carbon capture and storage technologies in existing coal-based, power generation. On May 7, 2010, the Company executed a cooperative agreement with the U.S. DOE which defines the basis for cost sharing in the development and initial operations of the facility. The project currently is in the design engineering phase. Construction would begin in late 2012 with commercial operations anticipated in the fourth quarter of 2014.

GenConn — GenConn, a 50/50 joint venture of NRG and The United Illuminating Company, or United Illuminating, formed to construct, own and operate peaking generation facilities in Connecticut, is in the construction phase of two, 200 MW peaking facilities at NRG’s Devon and Middletown sites. Each of these facilities is being constructed pursuant to 30-year contracts for differences with The Connecticut Light & Power Company. Three of the four units at the GenConn Devon facility were released to the ISO-NE during June 2010 and the last unit was released to ISO-NE in mid July 2010. The Middletown project, which is fully permitted, is in the advanced stages of construction, with a target commercial operation date of June 1, 2011.

Thermal Acquisition

Northwind Phoenix, LLC — On June 22, 2010, NRG, through NRG Thermal, acquired Northwind Phoenix, which owns and operates a district cooling system in Phoenix and provides chilled water, steam and electricity in metropolitan Tucson and to portions of Arizona State University. See Note 4, Business Acquisitions and Dispositions, to this Form 10-Q for further discussion.

Announced Wholesale Generation Acquisitions

Dynegy Plants — On August 13, 2010, NRG signed a definitive agreement with Blackstone to purchase 3,884 MW of Dynegy assets in California and Maine. The Dynegy plants in California consist of 1,020 MW of combined cycle, 2,159 MW of steam turbine, and 165 MW of combustion turbine generating capacity, each gas-fired with the exception of an oil-fired combustion turbine. The Maine plant is a 540 MW gas-fired combined cycle facility. The acquisition is subject to the satisfaction of closing conditions, including the completion of Blackstone’s acquisition of Dynegy in a separately announced merger (which, itself, requires a vote by the shareholders of Dynegy), and the receipt of required government approvals. There are no assurances that the conditions to Blackstone’s acquisition of Dynegy will be satisfied or that Blackstone’s acquisition of Dynegy will be consummated on the terms agreed to, if at all. See Note 4, Business Acquisitions and Dispositions, to this Form 10-Q for further discussion.

Cottonwood — On August 12, 2010, NRG agreed to acquire Cottonwood, a 1,279 MW combined cycle natural gas plant in the Entergy zone of east Texas, from Kelson Limited Partnership. The Cottonwood acquisition is expected to close by year end, subject to customary closing conditions and regulatory approvals. See Note 4, Business Acquisitions and Dispositions, to this Form 10-Q for further discussion.

Upon closing, the Dynegy and Cottonwood assets will strengthen NRG’s regional and dispatch diversity by greatly expanding the Company’s load following mid-merit generation profile. The addition of combined cycle plants in northern California will expand capabilities across the state and advance the Company’s ability to “firm” renewable resources with highly efficient gas generation, while lowering the overall carbon intensity of NRG’s fleet. NRG currently contracts with Cottonwood, one of the newest and most efficient plants in the region, to support current long-term contracts in Louisiana, Arkansas and East Texas. Owning Cottonwood would allow for future contracting opportunities and would enable NRG to provide additional balancing and ancillary services.

These acquisitions, once completed, will build greater balance across the Company’s core operating regions. Capacity in the West region would more than double, constituting 19% of the overall domestic fleet, from 9% currently. The South Central region’s capacity would increase from 12% to 14% of the Company’s overall installed megawatts in the U.S.

Nuclear Innovation North America

NINA, NRG’s majority-owned subsidiary, is 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 Project. TANE, a wholly-owned subsidiary of Toshiba Corporation, is the minority owner of NINA. Based on its current NRC schedule, the Company expects to achieve commercial operation for Unit 3 in 2016 and commercial operation for Unit 4 approximately 12 months thereafter. The total rated capacity of STP Units 3 and 4 is expected to be approximately 3,000 MW, subject to NRC approval.

The STP Units 3 and 4 Project is currently in the final stages of the U.S. DOE loan guarantee program process. However, NINA and NRG cannot accurately predict at this time as to timing or certainty of a conditional commitment award from the U.S. DOE. The likelihood of NINA receiving a loan guarantee is largely dependent upon additional appropriations for nuclear development by Congress or other means of properly securing the necessary funding for additional nuclear loan guarantee volume. See Note 15, Commitments and Contingencies, to this Form 10-Q for further discussion.

On March 1, 2010, an agreement was reached with CPS for NINA to acquire a controlling interest in the STP Units 3 and 4 Project through a settlement of the litigation between the parties. See Note 15, Commitments and Contingencies, to this Form 10-Q for further discussion.

On April 8, 2010, NINA announced an agreement for the Building and Construction Trades Department, or BCTD, of the AFL-CIO to provide skilled union labor to construct STP Units 3 and 4. The BCTD is an alliance of 13 national and international unions that collectively represent over two million skilled craft professionals in the U.S. and Canada.

On May 10, 2010, NINA and TNEA signed an Investment and Option Agreement whereby TNEA agreed to acquire up to a 20% interest in NINA Investments Holdings LLC. See Note 15, Commitments and Contingencies, to this Form 10-Q for further discussion.

In November 2010, NINA intends to finalize negotiations on an amended and restated EPC Agreement, or the Amended and Restated EPC Agreement. As part of the negotiations around the Amended and Restated EPC Agreement, NINA intends to amend and restate the TANE Credit Facility in order to allow for the payment of services beyond purchases of long lead materials and equipment, as well as enter into incremental financing arrangements that will provide for additional funds to cover project costs.

Renewable Development and Acquisitions

As part of its core strategy, NRG intends to invest significantly in the development and acquisition of renewable energy projects, including wind, solar and biomass. NRG’s renewable strategy is intended to capitalize on first mover advantage in a high growth segment of NRG’s business, the Company’s existing regional presence in regions with attractive renewable resources and the prevalence, in the Company’s core markets, of state-mandated renewable portfolio standards. As a result, a brief description of the Company’s development efforts with respect to each renewable technology follows.

Green Mountain Acquisition

On September 16, 2010, NRG agreed to acquire Green Mountain. Austin-based Green Mountain, a leading retail provider of clean energy products and services, has residential and commercial customers primarily in Texas, Oregon, and the New York metropolitan region. Green Mountain also delivers renewable products and services to select utilities that are better for the environment, as well as providers in New York and New Jersey. Green Mountain, which will be managed and operated as a distinct retail business within NRG, offers cleaner electricity products from renewable sources and a variety of carbon offset products. The transaction, which is expected to close in November 2010, has received the required regulatory approvals, but remains subject to customary closing conditions. See Note 4, Business Acquisitions and Dispositions, to this Form 10-Q for further discussion.

Solar

NRG is developing a number of solar projects utilizing photovoltaic, or PV, as well as solar thermal technologies. Specifically, NRG has projects that have entered into off-take arrangements with Southern California Edison, Pacific Gas & Electric, and Tucson Electric Power, each of which will utilize either PV, or solar thermal technology. While each of these projects has a PPA in place, the development of these projects is subject to certain regulatory approvals, conditions and milestones which may affect the Company’s decision to pursue further development of one or more of these projects.

In September 2010, the Company, together with Eurus Energy America, announced they will build a 45 MW PV solar facility located in Kings County California, or the Avenal Project. The Avenal Project is composed of three sites — Avenal Park (6 MW), Sun City (20 MW) and Sand Drag (19 MW). The Avenal Project has secured construction financing on all three sites, with anticipated commercial operation in mid-2011. Power from the Avenal Project will be sold to Pacific Gas & Electric, under multiple 20-year PPAs.

NRG expects to break ground by year end on the Company’s first generation site in New Mexico, a 20 MW PV solar facility. Power from the project will be sold to El Paso Electric Co. under a 20-year PPA. The project will be built on a 210-acre privately owned parcel of industrial-zoned land near Santa Teresa, New Mexico, about 10 miles from El Paso, Texas. When completed by year end 2011, the New Mexico Solar Project will be one of the first large-scale solar projects built in New Mexico.

On October 27, 2010, the Company, through its wholly-owned subsidiary NRG Solar LLC, executed a Letter of Intent to partner with BrightSource Energy, Inc., or BSE, to construct, finance and operate the largest solar thermal technology project in the world, the 392 MW Ivanpah Solar Electric Generating System in southeastern California’s Mohave Desert, or the Ivanpah Project. NRG plans to become the lead investor in Ivanpah, investing up to $300 million in the Ivanpah Project over the next three years. The investment is subject to definitive documentation, which is anticipated to be executed by year end 2010. The Ivanpah Project is composed of three separate facilities — Ivanpah 1 (126 MW), Ivanpah 2 (133 MW), and Ivanpah 3 (133 MW), and all three facilities are expected to be fully operational by mid-2013. The Ivanpah Project has received a $1.375 billion conditional commitment from the U.S. DOE for a loan guarantee, and has obtained all necessary permits and approvals. Power from the Ivanpah Project will be sold to Southern California Edison and Pacific Gas & Electric, under multiple 20-25 year PPAs. Ivanpah is located approximately 50 miles northwest of Needles, California, about five miles from the Nevada border on federal land managed by the U.S. Department of Interior’s Bureau of Land Management.

Consistent with its business strategy, NRG is currently focused on early stage development efforts in a number of markets as well as conducting due diligence with respect to various equity investment opportunities for solar projects utilizing solar technologies that range from concentrated solar thermal to PV. In June 2010, NRG acquired a 450 MW pipeline of solar development projects from US Solar Ventures, an affiliate of Arclight Capital Partners, LLC. These development projects, which range in size from 20 MW to 99 MW, and have the potential to be operational between 2011 and 2013, do not at present have PPAs but they have valuable site control and interconnection rights. This acquisition increases NRG’s solar projects under development to 1,150 MW.

NRG’s efforts to date have focused on larger (by renewable standards) “utility” sized solar projects. However, in September 2010, the Company announced its involvement in smaller scale “distributed” solar in Arizona. As a first stage of the program, NRG Solar is building 12 large solar pavilions at four separate school districts in the area of Phoenix and Tucson. The solar cells on these pavilions, which will collectively generate more than 2.5 MW of power, are anticipated to be in operation by the end of the year.

Wind

Terrestrial Wind

On June 14, 2010, NRG acquired South Trent Wind LLC, owner of the South Trent wind farm, or South Trent, a 101 MW wind farm near Sweetwater, Texas. See Note 4, Business Acquisitions and Dispositions, to this Form 10-Q for further discussion.

Offshore Wind

On April 26, 2010, the U.S. Department of Interior through its reorganized Bureau of Ocean Energy Management, Regulation and Enforcement issued a request for interest, or RFI, in obtaining one or more commercial leases for the construction of a wind energy project on the Outer Continental Shelf off the coast of Delaware. The RFI process will determine if there is competitive interest in building on an ocean tract starting 7.5 miles due east of Rehoboth Beach, Delaware. NRG Bluewater Holdings LLC, or NRG Bluewater, plans to build the Mid-Atlantic Wind Park in an area inside this zone 13 miles from shore, running to more than 20 miles from shore for the farthest turbine. On June 25, 2010, NRG Bluewater, through its subsidiary Bluewater Wind Delaware LLC filed a response to the RFI. On September 7, 2010, the Delaware Public Service Commission approved NRG Bluewater’s amended PPA with Delmarva Power & Light Company, which extended certain deadline and milestone dates by an additional two years, including revising the initial commercial operation date to December 1, 2016.

Biomass

In April 2010, the Company was awarded a 10-year contract from the New York State Energy Research and Development Authority for power generated using renewable biomass fuel at its Dunkirk Generating Station in western New York. The project will produce up to 15 MW of the station’s total output by co-firing with clean wood biomass. The award was part of a competitive solicitation to award contracts for projects that deliver renewable energy to the New York wholesale power market and which will help the state reach its RPS goal to increase the proportion of renewable electricity sold in New York from 25 percent to 30 percent by 2015.

In addition to the Dunkirk project, NRG has a biomass project under development at its Montville Generating Station. The project would involve the repowering one of the facility’s existing units to produce up to 40 MW of electricity from locally sourced biomass. The project has received approval from the Connecticut Siting Council, and in April 2010 was awarded an air permit from the Connecticut Department of Environmental Protection. The Company is pursuing opportunities to sell the power on the New England power grid which will also help the state toward reaching its goal of 20 percent of electricity in the state generated by a Class-1 fuel source.

Electric Vehicle Development

In 2009, NRG began development of a services business to support the large-scale deployment of electric vehicles in Texas and elsewhere in the country. By 2011, and in coordination with the introduction of multiple plug-in vehicles by the automotive industry, NRG plans to offer a range of integrated products and services that enable both public and home charging of electric vehicles. In conjunction with this effort, NRG announced in November 2009 that it will work with Nissan Motor Co. to make the City of Houston a launch city for the broader use of electric vehicles. In November 2009, NRG announced a joint project with the City of Houston to add plug-in fleet vehicles as well as public charging stations to support them. In March 2010, NRG invested in Aptera Motors, Inc., a privately held electric vehicle, or EV, manufacturer expected to launch a production EV in 2011.

Retail Development

Reliant Energy is continuing its development efforts in smart energy by enhancing the products and services that provide energy usage insights, choices and convenience, and increasing the scale at which Reliant Energy can offer these services. During the third quarter of 2010 Reliant Energy reached a significant milestone of having five smart meter enabled products/services in the market and over 100,000 customers enrolled on smart meter enabled products and services.

Forward-looking Energy Hedge Price Trend

The Company’s 2011 pre-tax income is expected to be lower than 2010 due to lower energy hedge prices.

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 26, Guarantees, to the Company’s 2009 Form 10-K for additional discussion.

Retained or Contingent Interests

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

Derivative Instrument Obligations

The Company’s 3.625% Preferred Stock includes a feature which is considered an embedded derivative per 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, 2010, based on the Company’s stock price, the 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, 2010, 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. Two of these investments, GenConn Energy LLC and Sherbino, are variable interest entities for which NRG is not the primary beneficiary.

NRG’s pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $148 million as of September 30, 2010. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG.

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 2009 Form 10-K. Also see Note 15, Commitments and Contingencies, to 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, 2010.

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 and to hedge fuel requirements at generation facilities. 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. The following disclosures about fair value of derivative instruments provide an update to, and should be read in conjunction with, Fair Value of Derivative Instruments in Item 6 — Management’s Discussion and Analysis of Financial Condition and Results of Operations, of the Company’s 2009 Form 10-K.

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, Fair Value Measurements and Disclosures, or ASC 820. Specifically, these tables disaggregate realized and unrealized changes in fair value; disaggregate estimated fair values at September 30, 2010, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at September 30, 2010. The increase in NRG’s net derivative asset at September 30, 2010, as compared to December 31, 2009, was driven by the decreases in gas and power prices and the roll-off of trades that settled during the period.


Derivative Activity Gains/(Losses)	(In millions)

Fair value of contracts as of December 31, 2009	$	459
Contracts realized or otherwise settled during the period		(267	)
Changes in fair value		716

Fair value of contracts as of September 30, 2010	$	908


	Fair Value of Contracts as of September 30, 2010
	Maturity									Maturity
(In millions)	Less Than			Maturity			Maturity			in Excess			Total Fair
Fair value hierarchy gains/(losses)	1 Year			1-3 Years			4-5 Years			4-5 Years			Value

Level 1	$	(25	)	$	(88	)	$	(15	)	$	—		$	(128	)
Level 2		482			606			40			(47	)		1,081
Level 3		(50	)		(3	)		8			—			(45	)

Total	$	407		$	515		$	33		$	(47	)	$	908

The Company applies a credit reserve to reflect credit risk, which is calculated based on published default probabilities. As of September 30, 2010, the credit reserve resulted in a $6 million decrease in fair value which is composed of a $3 million loss in OCI and a $3 million loss in derivative revenue and cost of operations.

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 $226 million in the net value of derivatives as of September 30, 2010.

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, or U.S. GAAP. The preparation of these financial statements and related disclosures in compliance with U.S. 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. Any 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 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, contingencies and accounting for unbilled revenues.

Goodwill Impairment Analysis

As described in Critical Accounting Policies and Estimates — Goodwill and Other Intangible Assets, in the Company’s 2009 Form 10-K, the Company believes that assumptions about future power prices most significantly impact the fair value of its Texas reporting unit, or NRG Texas. The price of natural gas plays an important role in setting the price of electricity in many of the regions where NRG operates power plants, and forward natural gas prices have continued to decline since year-end 2009. At December 31, 2009, the Company estimated the fair value of NRG Texas’ invested capital to exceed its carrying value by approximately 25%. Assuming all other factors held constant, a hypothetical $1 drop in the Company’s long-term natural gas price view used in that estimate would not have caused the fair value of NRG Texas to fall below its carrying value, but would have significantly reduced the excess fair value over carrying value. During the third quarter of 2010, given the continued volatility in forward gas prices, the Company evaluated information from its preliminary 2010 long-term budgets for NRG Texas, as well as various market-derived data including market research forecasts, recent merger and acquisition activity and earnings multiples, and concluded that the fair value of NRG Texas more likely than not exceeded its carrying amount. Consequently, the Company will perform its annual goodwill impairment assessment in the fourth quarter of 2010. If long-term natural gas prices remain depressed or continue to drop for an extended period of time, the Company’s goodwill may become impaired in the future, which would result in a non-cash charge, not to exceed $1.7 billion.

ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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 NRG is exposed to in its normal business activities are commodity price risk, interest rate risk, liquidity risk, credit risk, and currency exchange risk. The following disclosures about market risk provide an update to, and should be read in conjunction with, Item 6A — Quantitative and Qualitative Disclosures About Market Risk, of the Company’s 2009 Form 10-K.

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. 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. 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. 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.

As of September 30, 2010, 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 $50 million.

The following table summarizes average, maximum and minimum VaR for NRG for the three and nine months ended September 30, 2010, and 2009:


(In millions)	2010		2009

VaR as of September 30	$	50	$	53

Three months ended September 30:
Average	$	55	$	49
Maximum		64		55
Minimum		50		42

Nine months ended September 30:
Average	$	54	$	42
Maximum		70		55
Minimum		37		28

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. The VaR for the derivative financial instruments calculated using the diversified VaR model as of September 30, 2010, for the entire term of these instruments entered into for both asset management and trading, was approximately $22 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.

In June 2010, in connection with the Blythe and South Trent financing transactions (see Note 8, Long-Term Debt to this Form 10-Q), the Company entered into a series of current and forward-starting interest rate swaps, intended to hedge the risks associated with floating interest rates. These swaps, which have a combined notional value of $103 million, mature on various dates through 2028.

As of September 30, 2010, the Company had various interest rate swap agreements with notional amounts totaling approximately $3.2 billion. If the swaps had been discontinued on September 30, 2010, the Company would have owed the counterparties approximately $117 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 immaterial.

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, 2010, a 1% change in interest rates would result in a $13 million change in interest expense on a rolling twelve month basis.

As of September 30, 2010, the fair value of the Company’s long-term debt and funded letter of credit was $10.6 billion and the related carrying amount was $10.4 billion. NRG estimates that a 1% decrease in market interest rates would have increased the fair value of the Company’s long-term debt and funded letter of credit by $400 million

Liquidity Risk

Liquidity risk arises from the general funding needs of NRG’s activities and in the management of the Company’s assets and liabilities. The Company is currently exposed to additional collateral posting if natural gas prices decline primarily due to the long natural gas equivalent position at various exchanges used to hedge NRG’s retail supply load obligations.

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 $159 million as of September 30, 2010, 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 $23 million as of September 30, 2010. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of September 30, 2010.

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, 2010, no letters of credit are outstanding to second lien counterparties. With changes in commodity prices, the letters of credit could grow to $64 million, the cap under the agreements.

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. NRG is exposed to counterparty credit risk through various activities including wholesale sales, fuel purchases and retail supply and retail customer credit risk through its retail load activities. See Note 5, Fair Value of Financial Instruments, to this Form 10-Q for discussions regarding counterparty credit risk and retail customer credit risk, and Note 7, Accounting for Derivative Instruments and Hedging Activities, to this Form 10-Q for discussion regarding credit risk contingent features.

Currency Exchange Risk

NRG’s foreign earnings and investments may be subject to foreign currency exchange risk, which NRG generally does not hedge. As these earnings and investments are not material to NRG’s consolidated results, the Company’s foreign currency exposure is limited.

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 of 2010 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.

PART II — OTHER INFORMATION

ITEM 1 — LEGAL PROCEEDINGS

For a discussion of material legal proceedings in which NRG was involved through September 30, 2010, 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 Related to NRG Energy, Inc. in NRG Energy, Inc.’s Annual Report on Form 10-K for the fiscal year ended December 31, 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		2010 Capital Allocation
For the period ended September 30, 2010	shares purchased		paid per share		plans or programs		Plan

First quarter 2010		—	$	—		—	$	180,000,000
Second quarter 2010		2,214,000		22.57		2,214,000		130,002,304
July 1 – July 31		—		—		—		130,002,304
August 1 – August 31		3,208,292		20.26		3,208,292		65,002,304
September 1 – September 30		—		—		—		65,002,304

Third quarter 2010 Total		3,208,292		20.26		3,208,292		65,002,304

Year-to-date		5,422,292	$	21.21		5,422,292	$	65,002,304

On February 23, 2010, the Company announced a plan to repurchase $180 million of common stock under the Company’s 2010 Capital Allocation Plan. The Company repurchased $50 million of common stock during second quarter of 2010. In August 2010, the Company entered into the ASR Agreement, under which the Company repurchased the remaining $130 million of common stock. In connection with this agreement, the Company paid $130 million and received 3,208,292 shares of our common stock in August 2010. Upon final settlement, which occurred on October 22, 2010, the Company received a settlement amount of 3,040,919 additional shares of common stock. The shares repurchased under the ASR Agreement complete the Company’s previously announced $180 million share buyback program for 2010.

ITEM 3 — DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4 — (REMOVED AND RESERVED)

ITEM 5 — OTHER INFORMATION

The Company currently intends to hold its 2011 Annual Meeting on April 27, 2011, which is more than 30 days from the anniversary of the 2010 Annual Meeting. As a result, NRG has modified stockholder proposal deadlines as set forth below.

In order for a stockholder proposal to be considered for inclusion in NRG’s Proxy Statement for its 2011 Annual Meeting, NRG’s Corporate Secretary must receive the proposal no later than the close of business on December 14, 2010, which is a reasonable time before NRG begins to print and mail the proxy materials for its 2011 Annual Meeting. Proposals must be sent via registered, certified, or express mail (or other means that allows the stockholder to determine when the proposal was received by the Corporate Secretary) to the Corporate Secretary, NRG Energy, Inc., 211 Carnegie Center, Princeton, New Jersey 08540. Proposals must contain the information required under NRG’s Bylaws, a copy of which is available upon request to NRG’s Corporate Secretary, and also must comply with the SEC’s regulations regarding the inclusion of stockholder proposals in Company sponsored proxy materials.

Alternatively, stockholders intending to present a proposal or nominate a director for election at the 2011 Annual Meeting without having the proposal or nomination included in the Company’s Proxy Statement must comply with the requirements set forth in the Company’s Bylaws. NRG’s Bylaws require, among other things, that its Corporate Secretary receive the proposal or nomination no earlier than the close of business on the 120th day, and no later than the close of business on the 90th day, prior to the first anniversary of the preceding year’s Annual Meeting, unless the 2011 Annual Meeting is more than 30 days before or more than 70 days after such anniversary date. Accordingly, because NRG’s 2011 Annual Meeting will be held on April 27, 2011, more than 30 days before the anniversary of NRG’s previous annual meeting, its Corporate Secretary must receive the proposal or nomination not earlier than December 28, 2010 and not later than January 27, 2011, which is the later of (i) the 90th day prior to the date of the 2011 Annual Meeting or (ii) the 10th day following the day on which the date of the 2011 Annual Meeting is first publicly announced by the Company. The proposal or nomination must contain the information required by the Bylaws, a copy of which is available upon request to its Corporate Secretary. If the stockholder does not meet the applicable deadlines or comply with the requirements of SEC Rule 14a-4, NRG may exercise discretionary voting authority under proxies it solicits to vote, in accordance with its best judgment, on any such proposal.

ITEM 6 — EXHIBITS


Exhibits
1.1		Purchase Agreement, dated August 17, 2010, among NRG Energy, Inc., the guarantors named therein and Citigroup Global Markets Inc., Banc of America Securities LLC and Deutsche Bank Securities Inc., as representatives of the several initial purchasers.(1)

4.1		Thirty-Sixth Supplemental Indenture, dated August 20, 2010, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York.(1)

4.2		Form of 8.25% Senior Note due 2020 (incorporated by reference to Exhibit 4.1).(1)

10.1		Registration Rights Agreement, dated August 20, 2010, among NRG Energy, Inc., the guarantors named therein and Citigroup Global Markets Inc., Banc of America Securities LLC and Deutsche Bank Securities Inc., as representatives of the several initial purchasers.(1)

10.2		The NRG Energy, Inc. Amended and Restated Long Term Incentive Plan.(2)

10.3		Purchase and Sale Agreement by and between Denali Merger Sub and NRG Energy, Inc. dated as of August 13, 2010.(3)

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 August 20, 2010.

(2)	Incorporated herein by reference to NRG Energy Inc.’s current report on Form 8-K filed on August 3, 2010.

(3)	Incorporated herein by reference to NRG Energy Inc.’s current report on Form 8-K filed on August 13, 2010.

SIGNATURES

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


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


	/s/ CHRISTIAN S. SCHADE
	Christian S. Schade
	Chief Financial Officer (Principal Financial Officer)


	/s/ JAMES J. INGOLDSBY
	James J. Ingoldsby
Date: November 4, 2010	Chief Accounting Officer (Principal Accounting Officer)

EXHIBIT INDEX


Exhibits
1.1		Purchase Agreement, dated August 17, 2010, among NRG Energy, Inc., the guarantors named therein and Citigroup Global Markets Inc., Banc of America Securities LLC and Deutsche Bank Securities Inc., as representatives of the several initial purchasers.(1)

4.1		Thirty-Sixth Supplemental Indenture, dated August 20, 2010, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York.(1)

4.2		Form of 8.25% Senior Note due 2020 (incorporated by reference to Exhibit 4.1).(1)

10.1		Registration Rights Agreement, dated August 20, 2010, among NRG Energy, Inc., the guarantors named therein and Citigroup Global Markets Inc., Banc of America Securities LLC and Deutsche Bank Securities Inc., as representatives of the several initial purchasers.(1)

10.2		The NRG Energy, Inc. Amended and Restated Long Term Incentive Plan.(2)

10.3		Purchase and Sale Agreement by and between Denali Merger Sub and NRG Energy, Inc. dated as of August 13, 2010.(3)

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 August 20, 2010.

(2)	Incorporated herein by reference to NRG Energy Inc.’s current report on Form 8-K filed on August 3, 2010.

(3)	Incorporated herein by reference to NRG Energy Inc.’s current report on Form 8-K filed on August 13, 2010.