Edgar Filing: NRG ENERGY, INC.

Large accelerated filer x

Accelerated filer o

Non-accelerated filer o

Smaller reporting company o

(Do not check if a smaller reporting company)

NRG 2012 09.30 10Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

		For the Quarterly Period Ended: September 30, 2012

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 x 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 x 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.

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

Yes o No x

As of October 31, 2012, there were 228,297,805 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	7
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES	7
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	50
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	84
ITEM 4 — CONTROLS AND PROCEDURES	86
PART II — OTHER INFORMATION	87
ITEM 1 — LEGAL PROCEEDINGS	87
ITEM 1A — RISK FACTORS	87
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	87
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES	87
ITEM 4 — MINE SAFETY DISCLOSURES	87
ITEM 5 — OTHER INFORMATION	87
ITEM 6 — EXHIBITS	88
SIGNATURES	89

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 Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or 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 that 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 Item 1A — Risk 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, 2011, and Item 1A — Risk Factors, in Part II, Item 1A of the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2012, including, but not limited to, 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;


•	NRG's ability to receive Federal loan guarantees or cash grants to support development projects;


•	Operating and financial restrictions placed on NRG and its subsidiaries that are contained in the indentures governing NRG's outstanding notes, in NRG's 2011Senior Credit Facility, and in debt and other agreements of certain of NRG subsidiaries and project affiliates generally;


•	NRG's ability to implement its strategy of developing and building new power generation facilities, including new solar projects;


•	NRG's ability to implement its econrg strategy of finding ways to address environmental challenges while taking advantage of business opportunities;


•	NRG's ability to implement its FORNRG strategy to increase cash from operations through operational and commercial initiatives, corporate efficiencies, asset strategy, and a range of other programs throughout the company to reduce costs or generate revenues;


•	NRG's ability to achieve its strategy of regularly returning capital to stockholders;


•	NRG's ability to maintain retail market share;


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


•	NRG's ability to successfully integrate and manage any acquired businesses;


•	NRG's ability to develop and maintain successful partnering relationships; and

•

NRG's successful and timely completion of the proposed merger with GenOn Energy, Inc., which could be materially and adversely affected by, among other things, resolving any litigation brought in connection with the proposed merger, the timing and terms and conditions of required stockholder, governmental and regulatory approvals, and the ability to maintain relationships with employees, customers or suppliers as well as the ability to integrate the businesses and realize cost savings.

Forward-looking statements speak only as of the date they were made, and NRG Energy, Inc. 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:



2011 Form 10-K		NRG’s Annual Report on Form 10-K for the year ended December 31, 2011

2011 Revolving Credit Facility		The Company's $2.3 billion revolving credit facility due 2016, a component of the 2011 Senior Credit Facility

2011 Senior Credit Facility		As of July 1, 2011, NRG's senior secured facility, comprised of a $1.6 billion term loan facility and a $2.3 billion revolving credit facility

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

Baseload capacity		Coal and nuclear 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

Capital Allocation Plan		Share repurchase and shareholder dividend program

Capital Allocation Program		NRG's plan of allocating capital between debt reduction, reinvestment in the business, share repurchases and shareholder dividends through the Capital Allocation Plan

CDWR		California Department of Water Resources

C&I		Commercial, industrial and governmental/institutional

CFTC		U.S. Commodity Futures Trading Commission

CO₂		Carbon dioxide

CPUC		California Public Utilities Commission

CSAPR		Cross-State Air Pollution Rule

Distributed Solar		Solar power projects, typically less than 20 MW in size (on an alternating current, or AC, basis), that primarily sell power produced to customers for usage on site, or are interconnected to sell power into the local distribution grid

DNREC		Delaware Department of Natural Resources and Environmental Control

Energy Plus		Energy Plus Holdings LLC

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

FERC		Federal Energy Regulatory Commission

GenOn		GenOn Energy, Inc.

GHG		Greenhouse Gases

Green Mountain Energy		Green Mountain Energy Company

GWh		Gigawatt hour



Heat Rate		A measure of thermal efficiency computed by dividing the total BTU content of the fuel burned by the resulting kWhs generated. Heat rates can be expressed as either gross or net heat rates, depending whether the electricity output measured is gross or net generation and is generally expressed as BTU per net kWh

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

ITC		Investment Tax Credit

LIBOR		London Inter-Bank Offered Rate

LTIP		Long-Term Incentive Plan

Mass		Residential and small business

Merger Agreement		Agreement and Plan of Merger by and among NRG Energy, Inc., Plus Merger Corporation and GenOn Energy, Inc. dated as of July 20, 2012

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

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

NYPSC		New York Public Service Commission

OCI		Other comprehensive income

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

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

SEC		United States Securities and Exchange Commission

Securities Act		The Securities Act of 1933, as amended



Senior Notes		The Company’s $6.2 billion outstanding unsecured senior notes, consisting of $270 million of 7.375% senior notes due 2017, $1.2 billion of 7.625% senior notes due 2018, $700 million of 8.5% senior notes due 2019, $800 million of 7.625% senior notes due 2019, $1.1 billion of 8.25% senior notes due 2020, $1.1 billion of 7.875% senior notes due 2021, and $990 million of 6.625% senior notes due 2023

SO₂		Sulfur dioxide

STP		South Texas Project — nuclear generating facility located near Bay City, Texas in which NRG owns a 44% interest

Term Loan Facility		Prior to July 1, 2011, a senior first priority secured term loan, of which approximately $608 million would have matured on February 1, 2013, and $990 million would have matured on August 31, 2015, and was a component of NRG’s Senior Credit Facility. On July 1, 2011, NRG replaced its Senior Credit Facility, including the Term Loan Facility, with the 2011 Senior Credit Facility.

U.S.		United States of America

U.S. DOE		U.S. Department of Energy

U.S. DOJ		U.S. Department of Justice

U.S. EPA		U.S. Environmental Protection Agency

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

Utility Scale Solar		Solar power projects, typically 20 MW or greater in size (on an alternating current, or AC, basis), that are interconnected into the transmission or distribution grid to sell power at a wholesale level

VaR		Value at Risk

VIE		Variable Interest Entity

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)	2012			2011			2012			2011
Operating Revenues
Total operating revenues	$	2,331		$	2,674		$	6,359		$	6,947
Operating Costs and Expenses
Cost of operations	1,726			2,053			4,618			4,985
Depreciation and amortization	239			238			703			665
Impairment charge on emission allowances	—			160			—			160
Selling, general and administrative	253			169			681			479
Acquisition-related transaction and integration costs	18			—			18			—
Development costs	9			11			26			32
Total operating costs and expenses	2,245			2,631			6,046			6,321
Operating Income	86			43			313			626
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates	4			16			26			26
Impairment charge on investment	(1		)	(3		)	(2		)	(495		)
Other income, net	10			5			14			13
Loss on debt extinguishment	(41		)	(32		)	(41		)	(175		)
Interest expense	(163		)	(164		)	(495		)	(504		)
Total other expense	(191		)	(178		)	(498		)	(1,135		)
Loss Before Income Taxes	(105		)	(135		)	(185		)	(509		)
Income tax benefit	(113		)	(80		)	(246		)	(815		)
Net Income/(Loss)	8			(55		)	61			306
Less: Net income attributable to noncontrolling interest	9			—			18			—
Net (Loss)/Income Attributable to NRG Energy, Inc.	(1		)	(55		)	43			306
Dividends for preferred shares	2			2			7			7
(Loss)/Income Available for Common Stockholders	$	(3	)	$	(57	)	$	36		$	299
(Loss)/Earnings Per Share Attributable to NRG Energy, Inc. Common Stockholders
Weighted average number of common shares outstanding — basic	228			240			228			243
Net (loss)/income per weighted average common share — basic	$	(0.01	)	$	(0.24	)	$	0.16		$	1.23
Weighted average number of common shares outstanding — diluted	228			240			230			245
Net (loss)/income per weighted average common share — diluted	$	(0.01	)	$	(0.24	)	$	0.16		$	1.22
Dividends Per Common Share	$	0.09		$	—		$	0.09		$	—

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS)/INCOME

(Unaudited)



	Three months ended September 30,						Nine months ended September 30,
	2012			2011			2012			2011
	(In millions)
Net Income/(Loss)	$	8		$	(55	)	$	61		$	306
Other comprehensive (loss)/income, net of tax
Unrealized loss on derivatives, net of income tax benefit of $24, $45, $76, and $131	(43		)	(76		)	(132		)	(225		)
Foreign currency translation adjustments, net of income tax benefit of $0, $16, $1 and $4	1			(27		)	(1		)	(5		)
Reclassification adjustment for translation gain realized upon sale of Schkopau, net of income tax expense of $6, $0, $6, and $0	(11		)	—			(11		)	—
Available-for-sale securities, net of income tax benefit/(expense) of $(1), $1, $(1), and $1	2			(1		)	2			(2		)
Defined benefit plans	—			—			—			1
Other comprehensive loss	(51		)	(104		)	(142		)	(231		)
Comprehensive (loss)/income	(43		)	(159		)	(81		)	75
Less: Comprehensive income attributable to noncontrolling interest	9			—			18			—
Comprehensive (loss)/income attributable to NRG Energy, Inc.	(52		)	(159		)	(99		)	75
Dividends for preferred shares	2			2			7			7
Comprehensive (loss)/income available for common stockholders	$	(54	)	$	(161	)	$	(106	)	$	68

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS



	September 30, 2012			December 31, 2011
(In millions, except shares)	(unaudited)
ASSETS
Current Assets
Cash and cash equivalents	$	1,610		$	1,105
Funds deposited by counterparties	76			258
Restricted cash	237			292
Accounts receivable — trade, less allowance for doubtful accounts of $39 and $23	1,075			834
Inventory	393			308
Derivative instruments	2,677			4,216
Cash collateral paid in support of energy risk management activities	98			311
Prepayments and other current assets	217			273
Total current assets	6,383			7,597
Property, plant and equipment, net of accumulated depreciation of $5,194 and $4,570	15,866			13,621
Other Assets
Equity investments in affiliates	649			640
Note receivable — affiliate and capital leases, less current portion	78			342
Goodwill	1,886			1,886
Intangible assets, net of accumulated amortization of $1,628 and $1,452	1,188			1,419
Nuclear decommissioning trust fund	469			424
Derivative instruments	309			450
Other non-current assets	392			336
Total other assets	4,971			5,497
Total Assets	$	27,220		$	26,715
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	374		$	87
Accounts payable	1,246			808
Derivative instruments	2,462			3,751
Deferred income taxes	15			127
Cash collateral received in support of energy risk management activities	76			258
Accrued expenses and other current liabilities	604			640
Total current liabilities	4,777			5,671
Other Liabilities
Long-term debt and capital leases	10,968			9,745
Nuclear decommissioning reserve	349			335
Nuclear decommissioning trust liability	277			254
Deferred income taxes	1,092			1,389
Derivative instruments	561			464
Out-of-market commodity contracts	161			183
Other non-current liabilities	896			756
Total non-current liabilities	14,304			13,126
Total Liabilities	19,081			18,797
3.625% convertible perpetual preferred stock (at liquidation value, net of issuance costs)	249			249
Commitments and Contingencies
Stockholders’ Equity
Common stock	3			3
Additional paid-in capital	5,388			5,346
Retained earnings	4,002			3,987
Less treasury stock, at cost — 76,505,718 and 76,664,199 shares, respectively	(1,920		)	(1,924		)
Accumulated other comprehensive (loss)/income	(68		)	74
Noncontrolling interest	485			183
Total Stockholders’ Equity	7,890			7,669
Total Liabilities and Stockholders’ Equity	$	27,220		$	26,715

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine months ended September 30,
	2012			2011
	(In millions)
Cash Flows from Operating Activities
Net income	$	61		$	306
Adjustments to reconcile net income to net cash provided by operating activities:
Distributions and equity in earnings of unconsolidated affiliates	8			8
Depreciation and amortization	703			665
Provision for bad debts	40			41
Amortization of nuclear fuel	29			31
Amortization of financing costs and debt discount/premiums	25			25
Loss on debt extinguishment	8			58
Amortization of intangibles and out-of-market commodity contracts	108			118
Amortization of unearned equity compensation	27			14
Changes in deferred income taxes and liability for uncertain tax benefits	(261		)	(829		)
Changes in nuclear decommissioning trust liability	25			20
Changes in derivative instruments	360			(201		)
Changes in collateral deposits supporting energy risk management activities	213			7
Impairment charge on investment	—			481
Impairment charge on emission allowances	—			160
Cash used by changes in other working capital	(288		)	(236		)
Net Cash Provided by Operating Activities	1,058			668
Cash Flows from Investing Activities
Acquisitions of businesses, net of cash acquired	(40		)	(352		)
Capital expenditures	(2,474		)	(1,355		)
Increase in restricted cash, net	(96		)	(92		)
Decrease/(increase) in restricted cash to support equity requirements for U.S. DOE funded projects	151			(316		)
(Increase)/decrease in notes receivable	(22		)	27
Purchases of emission allowances	(8		)	(27		)
Proceeds from sale of emission allowances	8			6
Investments in nuclear decommissioning trust fund securities	(341		)	(314		)
Proceeds from sales of nuclear decommissioning trust fund securities	316			294
Proceeds from renewable energy grants	49			—
Proceeds from sale of assets, net of cash disposed of	137			14
Investments in unconsolidated affiliates	—			(17		)
Other	(9		)	(29		)
Net Cash Used by Investing Activities	(2,329		)	(2,161		)
Cash Flows from Financing Activities
Payment of dividends to common and preferred stockholders	(28		)	(7		)
Payment for treasury stock	—			(378		)
Net payments for settlement of acquired derivatives that include financing elements	(65		)	(61		)
Sale proceeds and other contributions from noncontrolling interests in subsidiaries	316			—
Proceeds from issuance of long-term debt	2,541			5,710
Decrease in restricted cash supporting funded letter of credit	—			1,300
Payment for settlement of funded letter of credit facility	—			(1,300		)
Proceeds from issuance of common stock	—			2
Payment of debt issuance and hedging costs	(30		)	(149		)
Payments for short and long-term debt	(955		)	(5,450		)
Net Cash Provided/(Used) by Financing Activities	1,779			(333		)
Effect of exchange rate changes on cash and cash equivalents	(3		)	2
Net Increase/(Decrease) in Cash and Cash Equivalents	505			(1,824		)
Cash and Cash Equivalents at Beginning of Period	1,105			2,951
Cash and Cash Equivalents at End of Period	$	1,610		$	1,127

See accompanying 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 an integrated wholesale power generation and retail electricity company that aspires to be a leader in the way the industry and consumers think about, use, produce and deliver energy and energy services in major competitive power markets in the United States. First, NRG is a wholesale power generator engaged in the ownership and operation of power generation facilities; the trading of energy, capacity and related products; and the transacting in and trading of fuel and transportation services. Second, NRG is a retail electricity company engaged in the supply of electricity, energy services, and cleaner energy products to retail electricity customers in deregulated markets through its Retail businesses, which include Reliant Energy, Green Mountain Energy and Energy Plus. Finally, NRG is focused on the deployment and commercialization of potential disruptive clean energy technologies, like electric vehicles, Distributed Solar and smart meter technology, which have the potential to change the nature of the power supply industry.

The accompanying unaudited interim condensed consolidated financial statements have been prepared in accordance with the Securities and Exchange Commission's, or SEC's, regulations for interim financial information and with the instructions to Form 10-Q. Accordingly, they do not include all of the information and notes required by generally accepted accounting principles for complete financial statements. The following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to the Company's financial statements in its Annual Report on Form 10-K for the year ended December 31, 2011, or 2011 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, 2012, and the results of operations, comprehensive (loss)/income and cash flows for the three and nine months ended September 30, 2012, and 2011.

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 exclude capital expenditures of $712 million which were accrued and unpaid at September 30, 2012, primarily for solar projects under construction.

Noncontrolling Interests

The following table reflects the changes in NRG's noncontrolling interest balance:



	(In millions)
Balance as of December 31, 2011	$	183
Sale proceeds and cash contributions	284
Comprehensive income attributable to noncontrolling interest	18
Balance as of September 30, 2012	$	485

Tax Credits

NRG accounts for income taxes in accordance with Accounting Standards Codification, or ASC, 740, Income Taxes, or ASC 740, which requires that the Company use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences, as further described in Note 2, Summary of Significant Accounting Policies, to the Company's 2011 Form 10-K. NRG reduces its current income tax expense in the consolidated statement of operations for any investment tax credits, or ITCs, that are not convertible into cash grants, as well as other tax credits, in the period the tax credit is generated. ITCs that are convertible into cash grants, as well as the deferred income tax benefit generated by the difference in the financial statement and tax basis of the related assets, are recorded as a reduction to the carrying value of the underlying property and subsequently amortized to earnings on a straight-line basis over the useful life of each underlying property.

Recent Accounting Developments

Effective January 1, 2012, the Company adopted the provisions of Accounting Standards Update, or ASU, No. 2011-05, Comprehensive Income (Topic 220) Presentation of Comprehensive Income, or ASU No. 2011-05, and began presenting the total of comprehensive income, the components of net income and the components of other comprehensive income in two separate but consecutive statements. The provisions of ASU No. 2011-05 are required to be adopted retroactively. As this guidance provides only presentation requirements, the adoption of this standard did not impact the Company's results of operations, cash flows or financial position.

Note 3 — Business Acquisitions and Dispositions

Pending Acquisition

On July 20, 2012, the Company entered into an agreement, or the Merger Agreement, to acquire GenOn Energy, Inc., or GenOn. GenOn, a generator of wholesale electricity, has baseload, intermediate and peaking power generation facilities using coal, natural gas and oil, totaling approximately 22,700 MW. The Company will issue, as consideration for the acquisition, 0.1216 shares of NRG common stock for each outstanding share of GenOn, including restricted stock units outstanding, on the acquisition date, except for fractional shares which will be paid in cash. Based upon total GenOn shares outstanding as of September 30, 2012, the Company expects to issue approximately 94 million shares of NRG common stock, or 29% of total common shares outstanding following the close of the transaction.

NRG and GenOn will hold their respective special meetings of stockholders on November 9, 2012. The stockholders who held shares of NRG and GenOn on Friday, October 5, 2012, will be entitled to vote at their respective special meeting on the proposals pertaining to the merger of the companies.

On September 21, 2012, the Department of Justice and the Federal Trade Commission granted early termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. On October 25, 2012, the Public Utility Commission of Texas, or PUCT, approved the merger. Additionally, the 90-day prior notice period to the California Public Utilities Commission, or CPUC, required under California law expired on October 31, 2012.

The merger remains subject to the satisfaction or waiver of other closing conditions, including approval by the stockholders of both companies and regulatory approvals by the Federal Energy Regulatory Commission, or the FERC, and the New York Public Service Commission, or NYPSC. Additionally, the companies have requested a threshold determination by the U.S. Nuclear Regulatory Commission, or the NRC, that its approval is not required. The acquisition is expected to close by the first quarter of 2013.

2012 Dispositions

Agua Caliente

On January 18, 2012, the Company completed the sale of a 49% interest in NRG Solar AC Holdings LLC, the indirect owner of the Agua Caliente project, to MidAmerican Energy Holdings Company, or MidAmerican. A majority of the $122 million of cash consideration received at closing represented 49% of construction costs funded by NRG's equity contributions. The excess of the consideration over the carrying value of the divested interest was recorded to additional paid-in capital. MidAmerican will fund its proportionate share of future equity contributions and other credit support for the project. NRG continues to hold a majority interest in and consolidate the project.

Saale Energie GmbH

On July 17, 2012, the Company completed the sale of its 100% interest in Saale Energie GmbH, which holds a 41.9% interest in Kraftwerke Schkopau GbR and a 44.4% interest in Kraftwerke Schkopau Betriebsgesllschaft mbH, collectively, Schkopau. Schkopau holds a fixed 400 MW participation in the 900 MW Schkopau Power Station located in Germany. In connection with the sale of Schkopau, NRG entered into a foreign currency swap contract to hedge the impact of exchange rate fluctuations on the sale proceeds of €141 million. The Company received cash consideration, net of selling expenses, of $174 million, which included $4 million related to the settlement of the swap contract that was recorded as a gain within Other income, net in the quarter ended September 30, 2012. The cash consideration approximated the book value of the net assets, including cash of $38 million, on the date of the sale.

2011 Acquisitions

The Company's acquisitions that are considered business combinations are accounted for under the acquisition method of accounting in accordance with ASC 805, Business Combinations, or ASC 805, with identifiable assets acquired and liabilities assumed provisionally recorded at their estimated fair values on the acquisition date. The provisional amounts recognized are subject to revision until the evaluations are completed and to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date, are required to be finalized within a measurement period not to exceed one year. The Company made several acquisitions in 2011, which were recorded as business combinations under ASC 805, for which the accounting was not finalized as of December 31, 2011. See Note 3, Business Acquisitions and Dispositions and Note 12, Debt and Capital Leases, in the Company's 2011 Form 10-K, for additional information related to these acquisitions.

The accounting for the acquisitions of Energy Plus, California Valley Solar Ranch, or CVSR, Agua Caliente and Ivanpah were completed as of March 31, 2012, at which point the provisional fair values became final with no material changes.

Note 4 — Nuclear Innovation North America LLC, or NINA, Impairment Charge

As discussed in detail in Note 4, Nuclear Innovation North America LLC Developments, Including Impairment Charge, to the Company's 2011 Form 10-K, NRG deconsolidated NINA as of March 31, 2011, and recorded an impairment charge of $495 million for the nine months ended September 30, 2011, including $481 million in the quarter ended March 31, 2011 for the full amount of its investment, $11 million in the quarter ended June 30, 2011 and $3 million for the quarter ended September 30, 2011.

Note 5 — Fair Value of Financial Instruments

This footnote should be read in conjunction with the complete description under Note 5, Fair Value of Financial Instruments, to the Company's 2011 Form 10-K.

For cash and cash equivalents, funds deposited by counterparties, restricted cash, and cash collateral paid and received in support of energy risk management activities, the carrying amount approximates fair value because of the short-term maturity of those instruments. Debt securities, equity securities, trust fund investments, which are comprised of various U.S. debt and equity securities, and derivative assets and liabilities are carried at fair market value.

The estimated carrying values and fair values of NRG's recorded financial instruments not carried at fair market value are as follows:



	As of September 30, 2012				As of December 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Assets:
Notes receivable	$	84	$	84	$	156	$	161
Liabilities:
Long-term debt, including current portion	11,342		11,817		9,729		9,716

The fair value of the Company's publicly-traded long-term debt is based on quoted market prices and is classified as Level 1 within the fair value hierarchy. The fair value of debt securities, non publicly-traded long-term debt, and certain notes receivable of the Company are based on expected future cash flows discounted at market interest rates, or current interest rates for similar instruments with equivalent credit quality and are classified as Level 3 within the fair value hierarchy.

Recurring Fair Value Measurements

For cash and cash equivalents, funds deposited by counterparties, restricted cash, and cash collateral paid and received in support of energy risk management activities, the carrying amount approximates fair value because of the nature and short-term maturity of those instruments and are classified as Level 1 within the fair value hierarchy.

The following tables present 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:



	As of September 30, 2012
	Fair Value
(In millions)	Level 1		Level 2		Level 3		Total
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities	$	—	$	—	$	11	$	11
Marketable equity securities	1		—		—		1
Trust fund investments:
Cash and cash equivalents	4		—		—		4
U.S. government and federal agency obligations	34		—		—		34
Federal agency mortgage-backed securities	—		63		—		63
Commercial mortgage-backed securities	—		6		—		6
Corporate debt securities	—		72		—		72
Equity securities	240		—		46		286
Foreign government fixed income securities	—		5		—		5
Derivative assets:
Commodity contracts	1,733		1,226		27		2,986
Total assets	$	2,012	$	1,372	$	84	$	3,468
Derivative liabilities:
Commodity contracts	$	1,601	$	1,263	$	25	$	2,889
Interest rate contracts	—		134		—		134
Total liabilities	$	1,601	$	1,397	$	25	$	3,023



	As of December 31, 2011
	Fair Value
(In millions)	Level 1		Level 2		Level 3		Total
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities	$	—	$	—	$	7	$	7
Marketable equity securities	1		—		—		1
Trust fund investments:
Cash and cash equivalents	2		—		—		2
U.S. government and federal agency obligations	44		—		—		44
Federal agency mortgage-backed securities	—		63		—		63
Commercial mortgage-backed securities	—		7		—		7
Corporate debt securities	—		54		—		54
Equity securities	209		—		42		251
Foreign government fixed income securities	—		4		—		4
Derivative assets:
Commodity contracts	2,661		1,930		75		4,666
Total assets	$	2,917	$	2,058	$	124	$	5,099
Derivative liabilities:
Commodity contracts	$	2,757	$	1,283	$	67	$	4,107
Interest rate contracts	—		108		—		108
Total liabilities	$	2,757	$	1,391	$	67	$	4,215

There were no transfers during the three and nine months ended September 30, 2012, and 2011, between Levels 1 and 2. The following tables reconcile, for the three and nine months ended September 30, 2012, and 2011, the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements at least annually using significant unobservable inputs:



	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Three months ended September 30, 2012										Nine months ended September 30, 2012
	Debt Securities		Trust Fund Investments								Debt Securities		Trust Fund Investments
(In millions)	Debt Securities		Trust Fund Investments		Derivatives^(a)			Total			Debt Securities		Trust Fund Investments		Derivatives^(a)			Total
Beginning balance	$	9	$	43	$	171		$	223		$	7	$	42	$	8		$	57
Total gains/(losses) - realized/unrealized:
Included in earnings	—		—		(9		)	(9		)	—		—		(3		)	(3		)
Included in OCI	2		—		—			2			4		—		—			4
Included in nuclear decommissioning obligations	—		3		—			3			—		3		—			3
Purchases	—		—		(109		)	(109		)	—		1		(1		)	—
Transfers into Level 3 ^(b)	—		—		(31		)	(31		)	—		—		4			4
Transfers out of Level 3 ^(b)	—		—		(20		)	(20		)	—		—		(6		)	(6		)
Ending balance as of September 30, 2012	$	11	$	46	$	2		$	59		$	11	$	46	$	2		$	59
The amount of the total (losses)/gains for the period included in earnings attributable to the change in unrealized gains relating to assets still held as of September 30, 2012	$	—	$	—	$	(5	)	$	(5	)	$	—	$	—	$	1		$	1



	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Three months ended September 30, 2011												Nine months ended September 30, 2011
	Debt Securities			Trust Fund Investments									Debt Securities		Trust Fund Investments
(In millions)	Debt Securities			Trust Fund Investments			Derivatives^(a)			Total			Debt Securities		Trust Fund Investments			Derivatives^(a)			Total
Beginning balance	$	9		$	41		$	(26	)	$	24		$	8	$	39		$	(27	)	$	20
Total gains/(losses) - realized/unrealized:
Included in earnings	—			—			—			—			—		—			19			19
Included in OCI	(1		)	—			—			(1		)	—		—			—			—
Included in nuclear decommissioning obligations	—			(8		)	—			(8		)	—		(7		)	—			(7		)
Purchases	—			—			(2		)	(2		)	—		1			6			7
Transfers into Level 3 ^(b)	—			—			13			13			—		—			(17		)	(17		)
Transfers out of Level 3 ^(b)	—			—			8			8			—		—			12			12
Ending balance as of September 30, 2011	$	8		$	33		$	(7	)	$	34		$	8	$	33		$	(7	)	$	34
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, 2011	$	—		$	—		$	(1	)	$	(1	)	$	—	$	—		$	6		$	6


(a)	Consists of derivatives 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.

Derivative fair value measurements

The majority of NRG's contracts are exchange-traded contracts with readily available quoted market prices. A portion of NRG's contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter and on-line exchanges. For the majority of NRG markets, the Company receives quotes from multiple sources. To the extent that NRG receives multiple quotes, the Company's prices reflect the average of the bid-ask mid-point prices obtained from all sources that NRG believes provide the most liquid market for the commodity. If the Company receives one quote, then the mid-point of the bid-ask spread for that quote is used. The terms for which such price information is available vary by commodity, region and product. A significant portion of the fair value of the Company's derivative portfolio is based on price quotes from brokers in active markets who regularly facilitate those transactions and the Company believes such price quotes are executable. The Company does not use third party sources that derive price based on proprietary models or market surveys. The remainder of the assets and liabilities represent contracts for which external sources or observable market quotes are not available for the whole term or for certain delivery months or the contracts are retail and load following power contracts. These contracts are valued using various valuation techniques including but not limited to internal models that apply fundamental analysis of the market and corroboration with similar markets. Contracts valued with prices provided by models and other valuation techniques make up 1% of the total derivative assets and 1% of the total derivative liabilities.

The fair value of each contract is discounted using a risk free interest rate. In addition, the Company applies a credit reserve to reflect credit risk which is calculated based on published default probabilities. To the extent that NRG's net exposure under a specific master agreement is an asset, the Company uses the counterparty's default swap rate. If the exposure under a specific master agreement is a liability, the Company uses NRG's default swap rate. The credit reserve is added to the discounted fair value to reflect the exit price that a market participant would be willing to receive to assume NRG's liabilities or that a market participant would be willing to pay for NRG's assets. As of September 30, 2012, the credit reserve resulted in a $9 million increase in fair value which is composed of a $4 million gain in Other Comprehensive Income, or OCI, and a $5 million gain in operating revenue and cost of operations. As of September 30, 2011, the credit reserve resulted in a $15 million decrease in fair value which is composed of a $5 million loss in OCI and a $10 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 2011 Form 10-K, the following item is a discussion of the concentration of credit risk for the Company's contractual obligations. 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 arrangements, 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) 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 arrangements; 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. Risk 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, 2012, counterparty credit exposure to a portion of the Company's counterparties was $620 million and NRG held collateral (cash and letters of credit) against those positions of $28 million, resulting in a net exposure of $592 million. Counterparty credit exposure is valued through observable market quotes and discounted at the risk free rate. The following tables highlight net counterparty credit exposure by industry sector and by counterparty credit quality. 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 ^(a)
Category	(% of Total)
Financial institutions	46	%
Utilities, energy merchants, marketers and other	51
Coal and emissions	1
Independent System Operators, or ISOs	2
Total as of September 30, 2012	100	%



	Net Exposure ^(a)
Category	(% of Total)
Investment grade	63	%
Non-Investment grade	2
Non-rated ^(b)	35
Total as of September 30, 2012	100	%


(a)	Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market prices.


(b)	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.

NRG has counterparty credit risk exposure to certain counterparties representing more than 10% of total net exposure discussed above and the aggregate of such counterparties' exposure was $124 million. Approximately 83% of NRG's positions relating to this credit risk exposure roll-off by the end of 2013. 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 position or results of operations from nonperformance by any of NRG's counterparties.

Counterparty credit exposure described above excludes credit risk exposure under certain long term agreements, including California tolling agreements, South Central load obligations, and solar Power Purchase Agreements, or PPAs. 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, 2012, credit risk exposure to these counterparties attributable to NRG's ownership interests was approximately $1.1 billion for the next five years. This amount excludes potential credit exposures for projects with long term PPAs that have not reached commercial operations. 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. These factors significantly reduce the risk of loss.

Retail Customer Credit Risk

NRG is exposed to retail credit risk through the Company's retail electricity providers, which serve commercial, industrial and governmental/institutional, or C&I, customers and the residential and small business, or mass, market. 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, 2012, the Company's retail customer credit exposure was diversified across many customers and various industries, with a significant portion of the exposure with government entities.

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 Units 1 & 2, 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, because the Company's nuclear decommissioning activities are subject to approval by the PUCT with regulated rates that are designed to recover all decommissioning costs and that can be charged to and collected from the ratepayers per PUCT mandate. Since the Company is in compliance with 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 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 well as information about the contractual maturities of those securities.



	As of September 30, 2012							As of December 31, 2011
(In millions, except otherwise noted)	Fair Value		Unrealized Gains		Unrealized Losses		Weighted- average maturities (in years)	Fair Value		Unrealized Gains		Unrealized Losses		Weighted- average maturities (in years)
Cash and cash equivalents	$	4	$	—	$	—	—	$	2	$	—	$	—	—
U.S. government and federal agency obligations	33		2		—		11	43		3		—		10
Federal agency mortgage-backed securities	63		3		—		23	63		3		—		23
Commercial mortgage-backed securities	6		—		—		29	7		—		—		28
Corporate debt securities	72		4		—		11	54		3		1		10
Equity securities	286		143		—		—	251		113		1		—
Foreign government fixed income securities	5		—		—		6	4		—		—		8
Total	$	469	$	152	$	—		$	424	$	122	$	2

The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from these sales. The cost of securities sold is determined on the specific identification method.



	Nine months ended September 30,
	2012		2011
	(In millions)
Realized gains	$	8	$	4
Realized losses	5		3
Proceeds from sale of securities	316		294

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 2011 Form 10-K.

Energy-Related Commodities

As of September 30, 2012, NRG had energy-related derivative financial instruments extending through 2015, which are designated as cash flow hedges.

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, 2012, NRG had interest rate derivative instruments on recourse debt extending through 2013 and on non-recourse debt extending through 2030, the majority of which are designated as cash flow 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, 2012, and December 31, 2011. Option contracts are reflected using delta volume. Delta volume equals the notional volume of an option adjusted for the probability that the option will be in-the-money at its expiration date.



		Total Volume
Commodity	Units	September 30, 2012			December 31, 2011
		(In millions)
Emissions	Short Ton	(1		)	(2		)
Coal	Short Ton	34			37
Natural Gas	MMBtu	(244		)	13
Oil	Barrel	—			1
Power	MWh	12			4
Interest	Dollars	$	2,251		$	2,121

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, 2012		December 31, 2011		September 30, 2012		December 31, 2011
	(In millions)
Derivatives Designated as Cash Flow Hedges:
Interest rate contracts current	$	—	$	—	$	11	$	39
Interest rate contracts long-term	—		—		96		68
Commodity contracts current	1		318		2		—
Commodity contracts long-term	—		—		1		1
Total Derivatives Designated as Cash Flow Hedges	1		318		110		108
Derivatives Not Designated as Cash Flow Hedges:
Interest rate contracts current	—		—		13		—
Interest rate contracts long-term	—		—		14		1
Commodity contracts current	2,676		3,898		2,436		3,712
Commodity contracts long-term	309		450		450		394
Total Derivatives Not Designated as Cash Flow Hedges	2,985		4,348		2,913		4,107
Total Derivatives	$	2,986	$	4,666	$	3,023	$	4,215

Accumulated Other Comprehensive Income

The following table summarizes the effects of ASC 815, Derivatives and Hedging, or ASC 815, on the Company's accumulated OCI balance attributable to cash flow hedge derivatives, net of tax:



	Three months ended September 30, 2012									Nine months ended September 30, 2012
	Energy Commodities			Interest Rate			Total			Energy Commodities			Interest Rate			Total
	(In millions)
Accumulated OCI beginning balance	$	111		$	(68	)	$	43		$	188		$	(56	)	$	132
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts	(30		)	3			(27		)	(106		)	11			(95		)
Mark-to-market of cash flow hedge accounting contracts	(1		)	(15		)	(16		)	(2		)	(35		)	(37		)
Accumulated OCI ending balance, net of $12 tax	$	80		$	(80	)	$	—		$	80		$	(80	)	$	—
Gains/(losses) expected to be realized from OCI during the next 12 months, net of $38 tax	$	77		$	(11	)	$	66		$	77		$	(11	)	$	66
Losses recognized in income from the ineffective portion of cash flow hedges	$	—		$	—		$	—		$	(51	)	$	—		$	(51	)



	Three months ended September 30, 2011									Nine months ended September 30, 2011
	Energy Commodities			Interest Rate			Total			Energy Commodities			Interest Rate			Total
	(In millions)
Accumulated OCI beginning balance	$	332		$	(40	)	$	292		$	488		$	(47	)	$	441
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts	(91		)	—			(91		)	(281		)	11			(270		)
Mark-to-market of cash flow hedge accounting contracts	19			(4		)	15			53			(8		)	45
Accumulated OCI ending balance, net of $136 tax	$	260		$	(44	)	$	216		$	260		$	(44	)	$	216
Gains/(losses) expected to be realized from OCI during the next 12 months, net of $107 tax	$	186		$	(2	)	$	184		$	186		$	(2	)	$	184
Gains recognized in income from the ineffective portion of cash flow hedges	$	9		$	—		$	9		$	8		$	3		$	11

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.

Accounting guidelines require a high degree of correlation between the derivative and the hedged item throughout the period in order to qualify as a cash flow hedge. As of April 30, 2012, the Company's regression analysis for natural gas prices to ERCOT power prices, while positively correlated, did not meet the required threshold for cash flow hedge accounting for calendar year 2012. As a result, the Company de-designated its 2012 ERCOT cash flow hedges as of April 30, 2012, and prospectively marked these derivatives to market through the income statement.

Impact of Derivative Instruments on the Statement of Operations

Unrealized gains and losses associated with changes in the fair value of derivative instruments not accounted for as cash flow hedges and ineffectiveness of hedge derivatives are reflected in current period earnings.

The following table summarizes the pre-tax effects of economic hedges that have not been designated as cash flow hedges, ineffectiveness on cash flow hedges, and trading activity on the Company's statement of operations. The effect of commodity hedges is included within operating revenues and cost of operations and the effect of interest rate hedges is included in interest expense.



	Three months ended September 30,						Nine months ended September 30,
(In millions)	2012			2011			2012			2011
Unrealized mark-to-market results
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(85	)	$	50		$	(160	)	$	72
Reversal of (gain)/loss positions acquired as part of the Reliant Energy and Green Mountain Energy acquisitions	(15		)	(11		)	5			60
Net unrealized (losses)/gains on open positions related to economic hedges	(159		)	(7		)	(78		)	77
Gains/(losses) on ineffectiveness associated with open positions treated as cash flow hedges	—			9			(51		)	8
Total unrealized mark-to-market (losses)/gains for economic hedging activities	(259		)	41			(284		)	217
Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity	(15		)	8			(45		)	22
Net unrealized (losses)/gains on open positions related to trading activity	(3		)	—			33			22
Total unrealized mark-to-market(losses)/gains for trading activity	(18		)	8			(12		)	44
Total unrealized (losses)/gains	$	(277	)	$	49		$	(296	)	$	261



	Three months ended September 30,						Nine months ended September 30,
(In millions)	2012			2011			2012			2011
Revenue from operations — energy commodities	$	(395	)	$	89		$	(470	)	$	193
Cost of operations	118			(40		)	174			68
Total impact to statement of operations — energy commodities	$	(277	)	$	49		$	(296	)	$	261
Total impact to statement of operations — interest rate contracts	$	—		$	(1	)	$	(12	)	$	2

The reversal of gain or loss positions acquired as part of the Reliant Energy and Green Mountain Energy acquisitions were valued based upon the forward prices on the acquisition dates. The roll off amounts were offset by realized gains or losses at the settled prices and are reflected in the cost of operations during the same period.

For the nine months ended September 30, 2012, the unrealized loss from open economic hedge positions was primarily the result of a decrease in forward coal prices.

As of June 30, 2012 NRG had interest rate swaps designated as cash flow hedges on the Alpine solar project. The notional amount on the swaps exceeded the actual debt draws on the project. As such, NRG discontinued cash flow hedge accounting for these contracts and $4 million of loss previously deferred in OCI was recognized in earnings for the nine months ended September 30, 2012.

For the nine months ended September 30, 2011, the unrealized gain from open economic hedge positions was the result of an increase in value of forward purchases and sales of natural gas, 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 requires the Company to post additional collateral if there were a one notch downgrade in the Company's credit rating. The collateral required for contracts with adequate assurance clauses that are in a net liability position as of September 30, 2012, was $91 million. The collateral required for contracts with credit rating contingent features was $51 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 was approximately $56 million as of September 30, 2012.

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

Note 8 — Debt and Capital Leases

This footnote should be read in conjunction with the complete description under Note 12, Debt and Capital Leases, to the Company's 2011 Form 10-K.

Long-term debt and capital leases consisted of the following:



	September 30, 2012		December 31, 2011		Interest rate % ^(a)
	(In millions, except rates)
NRG Recourse Debt:
Senior notes, due 2023	$	990	$	—	6.625
Senior notes, due 2021	1,128		1,200		7.875
Senior notes, due 2020	1,100		1,100		8.250
Senior notes, due 2019	800		800		7.625
Senior notes, due 2019	692		691		8.500
Senior notes, due 2018	1,200		1,200		7.625
Senior notes, due 2017	270		1,090		7.375
Term loan facility, due 2018	1,577		1,588		L+3.00
Indian River Power LLC, tax-exempt bonds, due 2040	57		57		6.000
Indian River Power LLC, tax-exempt bonds, due 2045	157		148		5.375
Dunkirk Power LLC, tax-exempt bonds, due 2042	59		59		5.875
Fort Bend County, tax-exempt bonds, due 2038	16		—		Weekly per SIFMA rate	^(b)
Subtotal NRG Recourse Debt	8,046		7,933
NRG Non-Recourse Debt:
Ivanpah Financing:
Solar Partners I, due 2014 and 2033	443		290		1.126 - 3.991
Solar Partners II, due 2014 and 2038	453		314		1.116 - 4.195
Solar Partners VIII, due 2014 and 2038	411		270		1.381 - 4.256
NRG Peaker Finance Co. LLC, bonds, due 2019	194		190		L+1.07
Agua Caliente Solar, LLC, due 2037	541		181		2.395 - 3.256
NRG West Holdings LLC, term loan, due 2023	294		159		L+2.25 - 2.75
NRG Energy Center Minneapolis LLC, senior secured notes, due 2013, 2017 and 2025	141		151		5.95 - 7.31
CVSR - High Plains Ranch II LLC, due 2037	548		—		0.611 - 2.639
South Trent Wind LLC, financing agreement, due 2020	73		75		L+2.50 - 2.625
Solar Power Partners - SPP Fund II/IIB LLC term loans, due 2017	15		17		L+3.50
Solar Power Partners - SPP Fund III LLC term loan, due 2024	40		42		L+3.50
NRG Solar Roadrunner LLC, due 2031	46		61		L+2.01
NRG Solar Blythe LLC, credit agreement, due 2028	26		27		L+2.50
NRG Solar Avra Valley LLC	40		—		L+2.25
Other	31		19		various
Subtotal NRG Non-Recourse Debt	3,296		1,796

Subtotal long-term debt	11,342		9,729
Capital leases:
Saale Energie GmbH, Schkopau capital lease, due 2021	—		103
Subtotal	11,342		9,832
Less current maturities	374		87
Total long-term debt and capital leases	$	10,968	$	9,745

(a) L+ equals LIBOR plus x%.

(b) Securities Industry and Financial Markets Association, or SIFMA

Issuance of 2023 Senior Notes

6.625% 2023 Senior Notes

On September 24, 2012, NRG issued $990 million aggregate principal amount at par of 6.625% Senior Notes due 2023, or the 2023 Senior Notes. The 2023 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 a Supplemental Indenture, which is discussed in Note 12, Debt and Capital Leases, in the Company's 2011 Form 10-K. The Indenture and the form of the note provide, among other things, that the 2023 Senior Notes will be senior unsecured obligations of NRG.

The proceeds, net of issuance costs, of $978 million for the 2023 Senior Notes will be used to complete the tender offer of the 2017 Senior Notes, as discussed below. Interest is payable semi-annually beginning on March 15, 2013, until the maturity date of March 15, 2023.

Prior to September 15, 2015, NRG may redeem up to 35% of the aggregate principal amount of the 2023 Senior Notes with the net proceeds of certain equity offerings, at a redemption price of 106.625% of the principal amount. Prior to September 15, 2017, NRG may redeem all or a portion of the 2023 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 notes; or (ii) the excess of the principal amount of the note over the following: the present value of 103.313% of the note, plus interest payments due on the note from the date of redemption through September 15, 2017, discounted at a Treasury rate plus 0.50%. In addition, on or after September 15, 2017, 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 Period	Redemption Percentage
September 15, 2017 to September 14, 2018	103.313	%
September 15, 2018 to September 14, 2019	102.208	%
September 15, 2019 to September 14, 2020	101.104	%
September 15, 2020 and thereafter	100.000	%

In connection with the 2023 Senior Notes, NRG entered into a registration payment arrangement. For the first 90-day period immediately following a registration default, additional interest will be paid in an amount equal to 0.25% per annum of the principal amount of 2023 Senior Notes outstanding, as applicable. The amount of interest paid will increase by an additional 0.25% per annum with respect to each subsequent 90-day period until all registration defaults are cured, up to a maximum amount of interest of 1.0% per annum of the principal amount of the 2023 Senior Notes outstanding, as applicable. The additional interest is paid on the next scheduled interest payment date and following the cure of the registration default, the additional interest payment will cease.

Redemption of 2017 Senior Notes

On September 24, 2012, the Company redeemed $820 million of the 2017 Senior Notes through a tender offer, at an early redemption percentage of 104.125%. On October 9, 2012, an additional $0.4 million was tendered at a redemption percentage of 101.125%, and on October 24, 2012, the remaining $270 million of the 2017 Senior Notes were called, at a redemption percentage of 103.688%. Accordingly, the $270 million still outstanding as of September 30, 2012 was reclassified to current portion of long-term debt on the consolidated balance sheet. A loss on the extinguishment of the 2017 Senior Notes of $41 million was recorded during the three months ended September 30, 2012, and an additional $10 million was recorded in October, 2012; these losses primarily consisted of the premiums paid on the redemption and the write-off of previously deferred financing costs.

Fort Bend County Tax-Exempt Bonds

On May 3, 2012, NRG executed a $54 million tax-exempt bond financing with a maturity date of May 1, 2038, issued by the Fort Bend County Industrial Development Corporation, or the Fort Bend County Tranche A Bonds. The Fort Bend County Tranche A Bonds will be used for the construction of a peaking unit with one or more components of a carbon capture system at the W.A. Parish Generating Station in Thompsons, TX, or W.A. Parish. The bonds initially bore weekly interest based on the SIFMA rate, and were enhanced by a letter of credit under the Company's 2011 Revolving Credit Facility covering amounts drawn. The proceeds drawn through September 30, 2012 were $16 million, and the remaining balance will be drawn over time as construction and other qualifying costs are paid.

On October 18, 2012, NRG fixed the rate on the Fort Bend County Tranche A Bonds at 4.75% payable semiannually, and the letter of credit was canceled and replaced with an NRG guarantee. Also, the holders no longer have the option to tender the bonds at any time; accordingly, the outstanding balance as of September 30, 2012 was reclassified to long-term debt on the consolidated balance sheet.

On October 18, 2012, NRG also executed an additional $73 million tax-exempt bond financing, with a maturity date of November 1, 2042, also issued by the Fort Bend County Industrial Development Corporation, or the Fort Bend County Tranche B Bonds. The Fort Bend County Tranche B Bonds will be used for environmental and maintenance upgrades at W.A. Parish. The bonds were issued at a fixed rate of 4.75% payable semiannually, and are supported by an NRG guarantee. The proceeds will be drawn over time as qualifying expenditures are paid.

NRG Repowering Holdings LLC

On January 25, 2012, NRG Repowering Holdings LLC, or NRG Repowering, terminated its revolving credit facility, repaid the $5 million then outstanding, and a supporting letter of credit issued by NRG was returned.

On January 25, 2012, NRG Repowering entered into a Credit and Reimbursement Agreement which provides for a $10 million working capital facility that can be used for general corporate purposes or to issue letters of credit, and an $80 million letter of credit facility. Interest on the letters of credit accrues at 3.5% and on loans under the working capital facility at the London Inter-Bank Offered Rate, or LIBOR, plus 3.50%. The facility is secured by NRG Repowering's investments in GenConn Energy LLC and South Trent Wind LLC, and matures January 25, 2015. As of September 30, 2012, NRG Repowering had issued a $10 million letter of credit under the working capital facility and $80 million in letters of credit under the letter of credit facility.

Alpine Financing

On March 16, 2012, NRG, through its wholly-owned subsidiary, NRG Solar Alpine LLC, or Alpine, entered into a credit agreement with a group of lenders, or the Alpine Financing Agreement, for a $166 million construction loan that will convert to a term loan upon completion of the project and a $68 million cash grant loan. The construction loan has an interest rate of LIBOR plus an applicable margin of 2.50% and the cash grant loan has an interest rate of LIBOR plus an applicable margin of 2.25%. The term loan has an interest rate of LIBOR plus an applicable margin of 2.50%, which escalates 0.25% on the fifth anniversary of the term conversion. The term loan, which is secured by all the assets of Alpine, matures on the 10^th anniversary of the term conversion and amortizes based upon a predetermined schedule. The cash grant loan matures upon the earlier of the receipt of the cash grant or February 2013. The Alpine Financing Agreement also includes a letter of credit facility on behalf of Alpine of up to $37 million. Alpine pays an availability fee of 100% of the applicable margin on issued letters of credit. As of September 30, 2012, $2 million was outstanding under the construction loan, nothing was outstanding under the cash grant loans, and $10 million in letters of credit in support of the project were issued.

Also related to the Alpine Financing Agreement, on March 16, 2012, Alpine entered into a series of fixed for floating interest rate swaps for at least 85% of the outstanding term loan amount, intended to hedge the risks associated with floating interest rates. Alpine will pay its counterparty the equivalent of a 2.74% fixed interest payment on a predetermined notional value, and Alpine will receive quarterly the equivalent of a floating interest payment based on a one month LIBOR calculated on the same notional value through December 31, 2012 and based on a three month LIBOR from December 31, 2012 through the term loan maturity date. All interest rate swap payments by Alpine and its counterparty are made monthly through December 31, 2012, and quarterly thereafter and the LIBOR rate is determined in advance of each interest period. The notional amount of the swap, which became effective March 31, 2012, and matures on December 31, 2029, was $141 million as of September 30, 2012 and will increase and amortize in proportion to the loan.

Roadrunner Financing

On March 20, 2012, NRG, through its wholly-owned subsidiary, NRG Roadrunner LLC, or Roadrunner, received proceeds of $21 million under its cash grant application. These proceeds were used to repay Roadrunner's cash grant loan of $17 million plus accrued interest. The remaining cash was returned to NRG under the terms of the accounts agreement.

CVSR Financing

On March 9, 2012, NRG, through its wholly-owned subsidiary, High Plains Ranch II LLC, completed its first borrowing of $138 million under the CVSR Financing Agreement with the Federal Financing Bank. As of September 30, 2012, $548 million was outstanding under the loan.

Avra Valley Financing

On August 30, 2012, NRG, through its wholly-owned subsidiary, NRG Solar Avra Valley LLC, or Avra Valley, entered into a credit agreement with a bank, or the Avra Valley Financing Agreement, for a $66 million construction loan that will convert to a term loan upon completion of the project and an $8 million cash grant loan. Both the construction and cash grant loans have interest rates of LIBOR plus an applicable margin of 2.25%. The term loan has an interest rate of LIBOR plus an applicable margin of 2.25%, which escalates 0.25% on the fifth, tenth, and fifteenth anniversary of the term conversion. The term loan, which is secured by all the assets of Avra Valley, matures on the 18th anniversary of the term conversion and amortizes based upon a predetermined schedule. The cash grant loan matures upon the earlier of three days after the receipt of the cash grant or May 2013. The Avra Valley Financing Agreement also includes a letter of credit facility on behalf of Avra Valley of up to $4 million. Avra Valley pays an availability fee of 100% of the applicable margin on issued letters of credit. As of September 30, 2012, $40 million was outstanding under the construction loan, nothing was outstanding under the cash grant loans, and no letters of credit in support of the project were issued.

Also related to the Avra Valley Financing Agreement, on August 30, 2012, Avra Valley entered into a fixed for floating interest rate swap for at least 90% of the outstanding term loan amount, intended to hedge the risks associated with floating interest rates. Avra Valley will pay its counterparty the equivalent of a 2.333% fixed interest payment on a predetermined notional value, and Avra Valley will receive quarterly the equivalent of a floating interest payment based on a 3 month LIBOR calculated on the same notional value through the term loan maturity date. All interest rate swap payments by Avra Valley and its counterparty are made quarterly and the LIBOR rate is determined in advance of each interest period. The original notional amount of the swap, which becomes effective November 30, 2012, and matures on November 30, 2030 is $59 million and will amortize in proportion to the loan.

Note 9 — Variable Interest Entities, or VIEs

NRG has interests in entities that are considered VIEs under ASC 810, Consolidation, but NRG is not considered the primary beneficiary. NRG accounts for its interests in these entities under the equity method of accounting.

GenConn Energy LLC — Through its subsidiary, NRG Connecticut Peaking Development LLC, NRG owns a 50% interest in GenConn, a limited liability company which owns and operates two 200 MW peaking generation facilities in Connecticut at NRG's Devon and Middletown sites. NRG's maximum exposure to loss is limited to its equity investment, which was $125 million as of September 30, 2012.

Sherbino I Wind Farm LLC — NRG owns a 50% interest in Sherbino, a joint venture with BP Wind Energy North America Inc. NRG's maximum exposure to loss is limited to its equity investment, which was $92 million as of September 30, 2012.

Texas Coastal Ventures, LLC — NRG owns a 50% interest in Texas Coastal Ventures, a joint venture with Hilcorp Energy I, L.P., through its subsidiary Petra Nova LLC. NRG's maximum exposure to loss is limited to its equity investment, which was $53 million as of September 30, 2012.

Note 10 — Changes in Capital Structure

As of September 30, 2012, and December 31, 2011, the Company had 500,000,000 shares of common stock authorized. The following table reflects the changes in NRG's common shares issued and outstanding:



	Issued	Treasury		Outstanding
Balance as of December 31, 2011	304,183,720	(76,664,199	)	227,519,521
Shares issued under LTIP	608,128	—		608,128
Shares issued under ESPP	—	158,481		158,481
Balance as of September 30, 2012	304,791,848	(76,505,718	)	228,286,130

Employee Stock Purchase Plan — On April 25, 2012, NRG shareholders approved an increase of 1,000,000 shares available for issuance under the NRG Energy, Inc. Employee Stock Purchase Plan, or ESPP. At September 30, 2012, 1,018,870 shares of treasury stock were available for issuance under the ESPP.

Common Stock Dividends — On August 15, 2012, NRG paid its first quarterly dividend on the Company's common stock of $0.09 per share. On October 15, 2012, NRG declared a quarterly dividend on the Company's common stock of $0.09 per share, payable November 15, 2012, to shareholders of record as of November 1, 2012.

Note 11 — (Loss)/Earnings Per Share

Basic (loss)/earnings per common share is computed by dividing net (loss)/earnings less accumulated preferred stock dividends by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the year are weighted for the portion of the year that they were outstanding. Diluted (loss)/earnings per share is computed in a manner consistent with that of basic (loss)/earnings per share while giving effect to all potentially dilutive common shares that were outstanding during the period.

The reconciliation of NRG's basic and diluted (loss)/earnings per share is shown in the following table:



	Three months ended September 30,						Nine months ended September 30,
(In millions, except per share data)	2012			2011			2012			2011
Basic (loss)/earnings per share attributable to NRG common stockholders
Numerator:
Net (loss)/income attributable to NRG Energy, Inc.	$	(1	)	$	(55	)	$	43		$	306
Preferred stock dividends	(2		)	(2		)	(7		)	(7		)
Net (loss)/income attributable to NRG Energy, Inc. available to common stockholders	$	(3	)	$	(57	)	$	36		$	299
Denominator:
Weighted average number of common shares outstanding	228			240			228			243
Basic (loss)/earnings per share:
Net (loss)/income attributable to NRG Energy, Inc.	$	(0.01	)	$	(0.24	)	$	0.16		$	1.23
Diluted (loss)/earnings per share attributable to NRG common stockholders
Numerator:
Net (loss)/income attributable to NRG Energy, Inc. available to common shareholders	$	(3	)	$	(57	)	$	36		$	299
Denominator:
Weighted average number of common shares outstanding	228			240			228			243
Incremental shares attributable to the issuance of equity compensation (treasury stock method)	—			—			2			2
Total dilutive shares	228			240			230			245
Diluted (loss)/earnings per share:
Net (loss)/income attributable to NRG Energy, Inc.	$	(0.01	)	$	(0.24	)	$	0.16		$	1.22

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



	Three months ended September 30,		Nine months ended September 30,
(In millions of shares)	2012	2011	2012	2011
Equity compensation plans	11	7	6	7
Embedded derivative of 3.625% redeemable perpetual preferred stock	16	16	16	16
Total	27	23	22	23

Note 12 — Segment Reporting

Effective in fiscal year 2012, NRG's segment structure and its allocation of corporate expenses were updated to reflect how management currently makes financial decisions and allocates resources. The Company has recast the data from prior periods to reflect this change in reportable segments to conform to the current year presentation. The Company's businesses are primarily segregated based on the Retail businesses, conventional power generation, alternative energy businesses and corporate activities. Within NRG's conventional power generation operations, there are distinct components with separate operating results and management structures for the following geographical regions: Texas, Northeast, South Central, West and Other, which includes its international businesses, thermal and chilled water business and maintenance services. The Company's alternative energy businesses include solar and wind assets, electric vehicle services and the carbon capture business. Intersegment sales are accounted for at market.



(In millions)				Conventional Power Generation
Three months ended September 30, 2012	Retail^(a)			Texas^(a)		North- east^(a)		South Central		West		Other^(a)		Alternative Energy^(a)			Corporate^(a)(b)			Elimination			Total
Operating revenues	$	1,856		$	877	$	274	$	270	$	87	$	68	$	56		$	4		$	(1,161	)	$	2,331
Depreciation and amortization	41			115		32		23		3		4		18			3			—			239
Equity in earnings/(loss) of unconsolidated affiliates	—			—		3		—		4		2		(5		)	—			—			4
(Loss)/income before income taxes	(300		)	299		33		19		35		9		—			(200		)	—			(105		)
Net (loss)/income attributable to NRG Energy, Inc.	$	(300	)	$	299	$	33	$	19	$	35	$	9	$	(9	)	$	(87	)	$	—		$	(1	)
Total assets	$	3,179		$	12,109	$	1,945	$	1,676	$	909	$	692	$	5,615		$	18,076		$	(16,981	)	$	27,220



^(a) Includes intersegment sales and derivative gains and losses of:	$	3	$	1,126	$	6	$	—	$	—	$	12	$	10	$	4

^(b)Includes loss on debt extinguishment of $41 million.



(In millions)			Conventional Power Generation
Three months ended September 30, 2011	Retail^(c)		Texas^(c)(d)			North-east^(c)		South Central		West		Other^(c)		Alternative Energy^(c)			Corporate^(c)(e)			Elimination			Total
Operating revenues	$	1,861	$	817		$	298	$	279	$	45	$	81	$	10		$	5		$	(722	)	$	2,674
Depreciation and amortization	48		117			33		23		2		4		7			4			—			238
Equity in earnings/(loss) of unconsolidated affiliates	—		—			4		—		4		3		6			(1		)	—			16
Income/(loss) before income taxes	36		(45		)	6		21		27		7		(12		)	(175		)	—			(135		)
Net income/(loss) attributable to NRG Energy, Inc.	$	36	$	(45	)	$	6	$	21	$	27	$	5	$	(12	)	$	(93	)	$	—		$	(55	)



^(c) Includes intersegment sales and derivative gains and losses of:	$	4	$	697	$	3	$	—	$	—	$	6	$	5	$	5

^(d)Includes impairment charge on emission allowances of $160 million.

^(e)Includes loss on debt extinguishment of $32 million.



(In millions)			Conventional Power Generation
Nine months ended September 30, 2012	Retail^(f)		Texas^(f)			North-east^(f)			South Central		West		Other^(f)		Alternative Energy^(f)			Corporate^(f)(g)			Elimination			Total
Operating revenues	$	4,492	$	1,462		$	598		$	653	$	185	$	262	$	114		$	11		$	(1,418	)	$	6,359
Depreciation and amortization	126		343			96			69		8		12		41			8			—			703
Equity in earnings of unconsolidated affiliates	—		—			11			—		6		8		1			—			—			26
Income/(loss) before income taxes	504		(202		)	(20		)	—		42		29		(22		)	(516		)	—			(185		)
Net income/(loss) attributable to NRG Energy, Inc.	$	504	$	(202	)	$	(20	)	$	—	$	42	$	25	$	(40	)	$	(266	)	$	—		$	43



^(f) Includes intersegment sales and derivative gains and losses of:	$	3	$	1,287	$	51	$	—	$	—	$	55	$	18	$	4

^(g)Includes loss on debt extinguishment of $41 million.



(In millions)			Conventional Power Generation
Nine months ended September 30, 2011	Retail^(h)		Texas^(h)(i)		North-east^(h)			South Central		West		Other^(h)		Alternative Energy^(h)			Corporate^(h)(j)			Elimination			Total
Operating revenues	$	4,409	$	2,149	$	770		$	656	$	122	$	244	$	33		$	9		$	(1,445	)	$	6,947
Depreciation and amortization	114		347		89			65		7		11		22			10			—			665
Equity in earnings/(losses) of unconsolidated affiliates	—		—		9			—		9		9		—			(1		)	—			26
Income/(loss) before income taxes	347		193		(13		)	46		51		20		(42		)	(1,111		)	—			(509		)
Net income/(loss)attributable to NRG Energy, Inc.	$	350	$	193	$	(13	)	$	46	$	51	$	14	$	(42	)	$	(293	)	$	—		$	306



^(h) Includes intersegment sales and derivative gains and losses of:	$	4	$	1,401	$	5	$	—	$	—	$	15	$	13	$	5

⁽ⁱ⁾Includes impairment charge on emission allowances of $160 million.

^(j)Includes impairment charge on investment of $495 million, loss on debt extinguishment of $175 million, and tax benefit of $633 million resulting from the resolution of the federal tax audit.

Note 13 — Income Taxes

Effective Tax Rate

The income tax provision consisted of the following:



	Three months ended September 30,						Nine months ended September 30,
(In millions except otherwise noted)	2012			2011			2012			2011
Loss before income taxes	$	(105	)	$	(135	)	$	(185	)	$	(509	)
Income tax benefit	(113		)	(80		)	(246		)	(815		)
Effective tax rate	107.6		%	59.3		%	133.0		%	160.1		%

For the three and nine months ended September 30, 2012, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the income tax benefits resulting from generation of ITCs from the Company's Agua Caliente solar project in Arizona and production tax credits, or PTCs, generated from certain Texas wind facilities.

For the three and nine months ended September 30, 2011, NRG's overall effective tax rate for both of these periods was different than the statutory rate of 35% primarily due to the recognition of previously uncertain tax benefits that were effectively settled upon audit examination for years 2004 through 2006 and that were mainly composed of net operating losses of $536 million, which had been classified as capital loss carryforwards for financial statement purposes.

Uncertain tax benefits

As of September 30, 2012, NRG has recorded a non-current tax liability of $67 million for uncertain tax benefits from positions taken on various state tax returns, including accrued interest. NRG has accrued interest related to these uncertain tax benefits of $2 million for the nine months ended September 30, 2012, and has accrued $15 million of interest and penalties since adoption. The Company recognizes interest and penalties related to uncertain tax benefits in income tax expense.

The Company is currently under federal examination for tax years 2007 through 2010 and continues to be under examination by various state and foreign tax jurisdictions for multiple years.

Tax Receivable and Payable

As of September 30, 2012, NRG recorded a current domestic tax receivable of $52 million, of which $24 million is related to federal cash grants filed, $18 million is related to property tax refunds as a result of the New York State Empire Zone program and $10 million relates to Federal income tax refunds for prior year tax return filings. As of September 30, 2012, NRG has a current tax payable of $15 million that represents a tax liability due for domestic state taxes of $13 million, as well as foreign taxes payable of $2 million. In addition, we have recorded a $51 million non-current asset for Empire Zone credits generated in 2010 through 2012, for which the receipt of cash is deferred pursuant to New York State law.

Note 14 — Commitments and Contingencies

Commitments

First Lien Structure

NRG has granted first 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, 2012, in aggregate, the hedge portfolio under the lien was in-the-money.

Contingencies

Set forth below is a description of the Company's material legal proceedings. The Company believes that it has valid defenses to these legal proceedings and intends to defend them vigorously. Pursuant to the requirements of ASC 450, Contingencies and related guidance, NRG records reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. In addition, legal costs are expensed as incurred. Management has assessed each of the following matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, the Company is unable to predict the outcome of these legal proceedings or reasonably estimate the scope or amount of any associated costs and potential liabilities. As additional information becomes available, management adjusts its assessment and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of the Company's liabilities and contingencies could 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 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 CPUC 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, the FERC has not acted on remand.

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.

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 March 22, 2012, NRG reached an agreement in principle with the CPUC to settle and resolve this matter, including all related claims, on behalf of NRG and on behalf of Dynegy. The agreement in principle was announced by the Company on March 23, 2012, as well as by the CPUC and by the California Governor's Office. The documented agreement was executed and submitted to the FERC on April 27, 2012 for its approval, and remains pending. The settlement agreement contains three material elements to be fulfilled over a four to six year period, depending upon several factors. First, the settlement agreement includes a $20 million cash payment due 30 days after the FERC approval. Second, it includes the construction and operation of a fee-based charging network, to be owned and operated by NRG subsidiary, eVgo, which will consist of at least 200 publicly available fast-charging electric vehicle stations installed at locations across California. Last, it calls for the wiring and associated work required to improve at least 10,000 individual parking spaces to allow for the charging of electric vehicles in at least 1,000 multi-family complexes, worksites, and public interest locations such as community colleges, public universities, and public or non-profit hospitals. Although these improved newly wired parking spaces will continue to be owned by the local property owner, eVgo will have an 18-month exclusive right to obtain customers from these locations starting from the date of each completed installation. The expected $20 million cash payment was accrued and expensed in the statement of operations for the three months ended March 31, 2012. In addition, the Company expects to spend approximately $100 million over the next four to six year period, during which the Company will fulfill the other elements of the settlement, and will capitalize a substantial majority of the costs as property, plant and equipment, representing the costs to construct the charging network and the wiring, which will be productive assets. The Company will expense the costs to operate the assets as incurred. On May 24, 2012, ECOtality, Inc. filed a lawsuit against the CPUC challenging the settlement, which was effectively dismissed on October 12, 2012.

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 U.S. DOJ 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 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 environmental 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 January 17, 2012, LaGen filed a demand for a jury trial. On January 20, 2012, the court scheduled a liability-phase trial for October 15, 2012, and a remedy-phase trial set to occur at a later date to be determined in the event of an adverse decision in a liability-phase trial. On October 17, 2012, prior to the start of the liability-phase trial which had been temporarily adjourned, the parties notified the court that they had reached an agreement on terms of a settlement which requires final approval by the U.S. DOJ. The terms of the agreement generally require LaGen to install certain emission control technologies, as well as pay a civil penalty of $3.5 million and complete mitigation projects of $10.5 million within five years of entry of the Consent Decree. The Company anticipates entry of a Consent Decree by the court approximately ninety days after lodging. The Company is adequately reserved for this settlement. Further discussion on this matter can be found in Note 16, Environmental Matters - South Central Region, of this Form 10-Q.

In a related matter, soon after the filing of the above referenced U.S. DOJ lawsuit, LaGen sought insurance coverage from its insurance carrier, Illinois Union Insurance Company, or ILU. ILU denied coverage and thereafter LaGen filed a lawsuit (which was consolidated with a prior suit filed by ILU) seeking a declaration that ILU must provide coverage to LaGen for the defense costs incurred in defending the U.S. DOJ lawsuit. LaGen and ILU both filed motions for summary judgment and on January 30, 2012, the court issued an order granting LaGen's motion finding that ILU has a duty to defend LaGen. The trial court certified the summary judgment for immediate interlocutory appeal, and on May 25, 2012, ILU filed a petition with the U.S. Circuit Court of Appeals for the Fifth Circuit seeking to appeal the trial court's summary judgment ruling. The Fifth Circuit granted the petition on September 4, 2012. ILU filed a related notice of appeal on June 14, 2012, which also seeks review of the trial court's summary judgment ruling. The Company filed a motion to consolidate the two appeals which the court granted on October 24, 2012. Briefing on the appeals is currently ongoing.

Energy Plus Holdings, LLC Purported Class Actions

Energy Plus Holdings, LLC, or Energy Plus, is a defendant in five purported class action lawsuits, one in New York, one in New Jersey, one in Maryland and two in Pennsylvania. The plaintiffs in those lawsuits generally allege that Energy Plus misrepresents that its rates are competitive in the market; fails to disclose that its rates are substantially higher than those in the market and that Energy Plus has engaged in deceptive practices in its marketing of energy services. Plaintiffs generally seek that these matters be certified as class actions, with treble damages, interest, costs, attorneys' fees, and any other relief that the court deems just and proper. In addition, on July 26, 2012, the Connecticut Attorney General and Office of Consumer Counsel filed a petition with the Connecticut Public Utilities Regulatory Authority seeking to investigate Energy Plus' marketing practices. On August 7, 2012, Energy Plus Holdings LLC and Energy Plus Natural Gas LLC received a subpoena from the State of New York Office of Attorney General which generally seeks information and business records related to Energy Plus' sales, marketing and business practices. While we believe that these allegations are without merit, we are cooperating with the attorneys general and are exploring an amicable resolution of all matters. The Company does not currently anticipate any potential resolution to be material in nature and believes it is adequately reserved for any estimated losses.

Purported Class Actions related to July 22, 2012 Announcement of NRG/GenOn Merger Agreement

NRG Energy, Inc. has been named as a defendant in eight purported class actions pending in Texas and Delaware, related to its announcement of its agreement to acquire all outstanding shares of GenOn. These cases have been consolidated into one state court case in each of Delaware and Texas and a federal court case in Texas. The plaintiffs generally allege breach of fiduciary duties, as well as conspiracy, aiding and abetting breaches of fiduciary duties. Plaintiffs are generally seeking to: be certified as a class; enjoin the merger; direct the defendant to exercise their fiduciary duties; rescind the acquisition and be awarded attorneys' fees costs and other relief that the court deems appropriate. Plaintiffs have demanded that there be additional disclosures regarding the merger terms. On October 24, 2012, the parties to the Delaware state court case executed a Memorandum of Understanding to resolve the Delaware purported class action lawsuit.

Note 15 — Regulatory Matters

NRG operates in a highly regulated industry and is subject to regulation by various federal and state agencies. As such, NRG is affected by regulatory developments at both the federal and state levels and in the regions in which NRG operates. In addition, NRG is subject to the market rules, procedures, and protocols of the various Independent System Operator, or 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.

California — On May 4, 2010, in Southern California Edison Company v. FERC, the U.S. Court of Appeals for the D.C. Circuit vacated the FERC's acceptance of station power rules for the California Independent System Operator, or CAISO, market, and remanded the case for further proceedings at the FERC. On August 30, 2010, the 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, the FERC's ruling arguably 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). On February 28, 2011, the FERC issued an order denying rehearing. The Company, together with other generators, filed an appeal in the D.C. Circuit. The oral argument was held on September 19, 2012 and the decision is pending.

On November 18, 2011, Southern California Edison Company filed with the CPUC, seeking authorization to begin charging generators station power charges, and to assess such charges retroactively, which the Company and other generators have challenged. On August 13, 2012, the CPUC Energy Division issued a draft resolution in which it rejected the Company's arguments and approved Southern California Edison's proposed station power charges, including retroactive implementation. The CPUC Commissioners were scheduled to vote on the draft resolution on October 15, 2012. The draft resolution was withdrawn from the calendar and has not yet been rescheduled. The Company believes it has established an appropriate reserve.

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. Retail Electric Providers, or REPS, other market participants, ERCOT, and PUCT staff opposed Constellation's complaint. On January 25, 2008, the PUCT entered an order finding that ERCOT correctly settled the capacity insufficiency charges for the disputed dates in accordance with ERCOT protocols and denied Constellation's complaint. On April 9, 2008, Constellation appealed the PUCT order to the Civil District Court of Travis County, Texas and on June 19, 2009, the court issued a judgment reversing the PUCT order, finding that the ERCOT protocols were in irreconcilable conflict with each other. 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. 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. On October 6, 2010, the parties argued the appeal before the Court of Appeals for the Third District in Austin, Texas. On September 28, 2011, the Court of Appeals reversed the trial court decision, reinstating the PUCT's order, consistent with REPS's position. On January 13, 2012, Constellation filed a Petition for Review in the Supreme Court of Texas asking the Court to grant review of and reverse the Court of Appeals decision. The Texas Supreme Court requested that briefs on the merits be filed before deciding whether to hear the Petition for Review. Briefing is currently underway and the Company filed its brief on October 15, 2012.

Retail (Midwest ISO SECA) — Green Mountain Energy previously provided competitive retail energy supply in the Midwest ISO region during the relevant period of January 1, 2002, to December 31, 2005. By order dated November 18, 2004, the FERC eliminated certain regional through-and-out transmission rates charged by transmission owners in the regional electric grids operated by the Midwest Independent Transmission System Operator, Inc., or MISO, and PJM Interconnection, L.L.C., or PJM. In order to temporarily compensate the transmission owners for revenue lost as a result of the elimination of the through-and-out transmission rates, the FERC also ordered MISO, PJM and their respective transmission owners to provide for the recovery of certain Seams Elimination Charge/Cost Adjustments/Assignments, or SECA, charges effective December 1, 2004, through March 31, 2006, based on usage during 2002 and 2003. The tariff amendments filed by MISO and the MISO transmission owners allocated certain SECA charges to various zones and sub-zones within MISO, including a sub-zone called the Green Mountain Energy Company Sub-zone. Over the last several years, there has been extensive litigation before the FERC relating to these charges, seeking, among other things, to recover monies from Green Mountain Energy, and before the federal appellate courts. Green Mountain Energy has not paid any asserted SECA charges.

On May 21, 2010, the FERC issued two orders. In its Order on Rehearing, the FERC denied all requests for rehearing of its past orders directing and accepting the SECA compliance filings of MISO, PJM, and the transmission owners. In its Order on Initial Decision, the FERC: (1) affirmed an order by the Administrative Law Judge granting Green Mountain Energy partial summary judgment and holding Green Mountain Energy not liable for SECA charges for January - March 2006; and (2) reversed an August 2006 determination by the Administrative Law Judge that Green Mountain Energy could be held directly liable for some amount of SECA charges. The Order on Initial Decision also directed that the two Regional Transmission Organizations, or RTOs, and their respective transmission owners submit further compliance filings, which were filed on August 19, 2010. The FERC has not yet ruled on those compliance filings.

With regard to the SECA charges that had been invoiced to Green Mountain Energy, the FERC determined that most of those charges, approximately $22 million plus interest, were owed not by Green Mountain Energy but rather by BP Energy — one of Green Mountain Energy's suppliers during the period at issue. On August 19, 2010, the transmission owners and MISO made compliance filings in accordance with the FERC's Orders allocating SECA charges to a BP Energy Sub-zone, and making no allocation to a Green Mountain Energy sub-zone. BP Energy has not asserted any contractual claims against Green Mountain Energy. The Company believes it has established an appropriate reserve.

On September 30, 2011, the FERC issued orders denying BP Energy's request for rehearing of the May 2010 Order on Rehearing, denying all requests for rehearing of the Order on Initial Decision, and again determined that SECA charges were not owed by Green Mountain Energy. Numerous parties have sought judicial review of the FERC's Order on Initial Decision, and BP Energy has sought judicial review of the May 2010 Order on Rehearing. These appeals have been consolidated with previous appeals of orders relating to SECA before the U.S. Court of Appeals for the DC Circuit. Green Mountain Energy has been granted intervenor status in the consolidated appeals.

On May 10, 2012, the Court issued an order setting out a briefing schedule which provided for the submittal of petitioners' briefs on July 17, 2012. On July 5, 2012, BP Energy and three PJM transmission owners filed a motion asking the Court to vacate the briefing schedule. The movants stated that respondent FERC and all other petitioners either supported or did not oppose the motion. The movants further stated that they had reached a settlement resolving all SECA claims involving BP Energy, were filing the settlement agreement with the FERC that day, and desired a vacation of the briefing schedule to enable the FERC to act on the proposed settlement. The movants did in fact file the settlement agreement at the FERC that day. The agreement provided for BP Energy to pay a total of approximately $24 million to the three transmission owners signing the agreement, with another $1 million offered to the remaining PJM transmission owners, should they choose to join the settlement. The FERC approved the settlement agreement by order dated August 22, 2012 and the deadline for seeking rehearing of that order passed without any parties seeking rehearing. The settlement became effective on September 21, 2012, triggering a ten-day period during which other PJM transmission owners could choose to opt-in to the settlement by filing a notification of their choice with the FERC. All have done so.

In response to a July 10, 2012 D.C. Circuit order granting the July 5, 2012 motion to vacate the briefing schedule and directing the remaining parties to submit a motion to govern further proceedings by September 17, 2012, the parties filed a joint motion on that date requesting the continued abeyance of the consolidated proceedings. The motion stated that BP Energy would withdraw its petitions for review once the BP Energy settlement agreement became effective and noted that some of the remaining petitioners were involved in on-going settlement discussions. On September 24, 2012, the D.C. Circuit granted the motion and directed the parties to file motions to govern future proceedings by November 19, 2012. BP Energy filed a motion to withdraw its two petitions for review on September 25, 2012, which motion was granted by court orders dated September 27, 2012.

Note 16 — Environmental Matters

NRG is subject to a wide range of environmental regulations across a broad number of jurisdictions in the development, ownership, construction and operation of domestic and international projects. These laws and regulations generally require that governmental permits and approvals be obtained before construction and during operation of power plants. Environmental regulations have become increasingly stringent and NRG expects this trend to continue. The electric generation industry is likely to face new requirements to address various emissions, including greenhouse gases, as well as combustion byproducts and water use. In general, future laws and regulations are expected to require the addition of emissions controls or other environmental quality equipment or the imposition of certain restrictions on the operations of the Company's facilities, which could have a material effect on the Company's operations or competitive position.

Environmental Capital Expenditures

Based on current rules, technology and plans as well as preliminary plans based on proposed rules, NRG has estimated that environmental capital expenditures from 2012 through 2016 to meet NRG's regulatory environmental commitments will be approximately $440 million. These costs are primarily associated with mercury controls to satisfy the Mercury and Air Toxics Standards, or MATS, on the Company's Big Cajun II, W.A. Parish and Limestone facilities and a number of intake modification projects across the fleet under state or proposed federal 316(b) rules. The change from our previous estimate of $553 million reflects a decrease in costs related to changes in technology related to MATS compliance, completing projects below budget, and shifts in compliance schedules based on regulatory changes.

NRG continues to explore cost effective compliance alternatives to reduce costs. While this estimate reflects anticipated schedules and controls related to the proposed 316(b) Rule (the EPA pushed back the final 316(b) rule from July 2012 to July 2013), the full impact on the scope and timing of environmental retrofits from any new or revised regulations cannot be determined until these rules are final and any legal challenges are reviewed. However, NRG believes it is positioned to meet more stringent environmental regulations through its planned capital expenditures, existing controls, and increasing generation from renewable resources.

NRG's current contracts with the Company's rural electric cooperative customers in the South Central region allow for recovery of a portion of the region's environmental capital costs incurred as the result of complying with any change in environmental law. Cost recoveries begin once the environmental equipment becomes operational and include a capital return. The actual recoveries will depend, among other things, on the timing of the completion of the capital projects 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 approved, 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.

South Central Region

On September 7, 2012, LaGen received a Consolidated Compliance Order & Notice of Potential Penalty, or CCO&NPP, from the LDEQ. The CCO&NPP alleges that there were opacity exceedance events from the three electric generating units at the Big Cajun II power plant facility on certain dates and times during the years 2007-2012. On October 8, 2012, LaGen filed a Request for Administrative Adjudicatory Hearing in response to the CCO&NPP. Pending this hearing, LaGen is cooperating with the LDEQ and responding in good faith to the CCO&NPP. NRG is unable to predict the outcome of this matter at this preliminary stage of the proceeding.

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. On October 17, 2012, prior to the start of liability-phase trial which had been temporarily adjourned, the parties notified the court that they had reached an agreement on terms of a settlement which requires final approval by the U.S. DOJ. The terms of the agreement generally require LaGen to install certain emission control equipment technologies, which are not expected to have an adverse impact on NRG's planned environmental capital expenditures. Further discussion on this matter can be found in Note 14, Commitments and Contingencies, of this Form 10-Q.

Note 17 — Condensed Consolidating Financial Information

As of September 30, 2012, the Company had outstanding $6.2 billion of Senior Notes due from 2017 - 2023, as shown in Note 8, Debt and Capital Leases. These Senior Notes are guaranteed by certain of NRG's current and future wholly-owned domestic subsidiaries, or guarantor subsidiaries. The non-guarantor subsidiaries include all of NRG's foreign subsidiaries and certain domestic subsidiaries.

Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of September 30, 2012:



Arthur Kill Power LLC	NEO Freehold-Gen LLC	NRG Power Marketing LLC
Astoria Gas Turbine Power LLC	NEO Power Services Inc.	NRG Renter's Protection LLC
Cabrillo Power I LLC	New Genco GP, LLC	NRG Retail LLC
Cabrillo Power II LLC	Norwalk Power LLC	NRG Rockford Acquisition LLC
Carbon Management Solutions LLC	NRG Affiliate Services Inc.	NRG Saguaro Operations Inc.
Clean Edge Energy LLC	NRG Artesian Energy LLC	NRG Security LLC
Conemaugh Power LLC	NRG Arthur Kill Operations Inc.	NRG Services Corporation
Connecticut Jet Power LLC	NRG Astoria Gas Turbine Operations Inc.	NRG SimplySmart Solutions LLC
Cottonwood Development LLC	NRG Bayou Cove LLC	NRG South Central Affiliate Services Inc.
Cottonwood Energy Company LP	NRG Cabrillo Power Operations Inc.	NRG South Central Generating LLC
Cottonwood Generating Partners I LLC	NRG California Peaker Operations LLC	NRG South Central Operations Inc.
Cottonwood Generating Partners II LLC	NRG Cedar Bayou Development Company, LLC	NRG South Texas LP
Cottonwood Generating Partners III LLC	NRG Connecticut Affiliate Services Inc.	NRG Texas C&I Supply LLC
Cottonwood Technology Partners LP	NRG Construction LLC	NRG Texas Holding Inc.
Devon Power LLC	NRG Development Company Inc.	NRG Texas LLC
Dunkirk Power LLC	NRG Devon Operations Inc.	NRG Texas Power LLC
Eastern Sierra Energy Company LLC	NRG Dispatch Services LLC	NRG Unemployment Protection LLC
El Segundo Power, LLC	NRG Dunkirk Operations Inc.	NRG Warranty Services LLC
El Segundo Power II LLC	NRG El Segundo Operations Inc.	NRG West Coast LLC
Elbow Creek Wind Project LLC	NRG Energy Labor Services LLC	NRG Western Affiliate Services Inc.
Energy Plus Holdings LLC	NRG Energy Services Group LLC	O'Brien Cogeneration, Inc. II
Energy Plus Natural Gas LLC	NRG Energy Services LLC	ONSITE Energy, Inc.
Energy Protection Insurance Company	NRG Generation Holdings, Inc.	Oswego Harbor Power LLC
Everything Energy LLC	NRG Home & Business Solutions LLC	RE Retail Receivables, LLC
GCP Funding Company, LLC	NRG Home Solutions Product LLC	Reliant Energy Northeast LLC
Green Mountain Energy Company	NRG Huntley Operations Inc.	Reliant Energy Power Supply, LLC
Green Mountain Energy Company	NRG Identity Protect LLC	Reliant Energy Retail Holdings, LLC
(NY Com) LLC	NRG Ilion Limited Partnership	Reliant Energy Retail Services, LLC
Green Mountain Energy Company	NRG Ilion LP LLC	RERH Holdings, LLC
(NY Res) LLC	NRG International LLC	Saguaro Power LLC
Huntley Power LLC	NRG Maintenance Services LLC	Somerset Operations Inc.
Independence Energy Alliance LLC	NRG Mextrans Inc.	Somerset Power LLC
Independence Energy Group LLC	NRG MidAtlantic Affiliate Services Inc.	Texas Genco Financing Corp.
Independence Energy Natural Gas LLC	NRG Middletown Operations Inc.	Texas Genco GP, LLC
Indian River Operations Inc.	NRG Montville Operations Inc.	Texas Genco Holdings, Inc.
Indian River Power LLC	NRG New Jersey Energy Sales LLC	Texas Genco LP, LLC
Keystone Power LLC	NRG New Roads Holdings LLC	Texas Genco Operating Services, LLC
Langford Wind Power, LLC	NRG North Central Operations Inc.	Texas Genco Services, LP
Louisiana Generating LLC	NRG Northeast Affiliate Services Inc.	US Retailers LLC
Meriden Gas Turbines LLC	NRG Norwalk Harbor Operations Inc.	Vienna Operations Inc.
Middletown Power LLC	NRG Operating Services, Inc.	Vienna Power LLC
Montville Power LLC	NRG Oswego Harbor Power Operations Inc.	WCP (Generation) Holdings LLC
NEO Corporation	NRG PacGen Inc.	West Coast Power LLC

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

The following condensed consolidating financial information presents the financial information of NRG Energy, Inc., the guarantor subsidiaries and the non-guarantor subsidiaries in accordance with Rule 3-10 under the Securities and Exchange Commission's Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiaries or non-guarantor subsidiaries operated as independent entities.

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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Three Months Ended September 30, 2012

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Operating Revenues
Total operating revenues	$	2,237		$	120		$	—		$	(26	)	$	2,331
Operating Costs and Expenses
Cost of operations	1,701			47			1			(23		)	1,726
Depreciation and amortization	217			20			2			—			239
Selling, general and administrative	168			14			74			(3		)	253
Acquisition-related transaction and integration costs	—			—			18			—			18
Development costs	—			—			9			—			9
Total operating costs and expenses	2,086			81			104			(26		)	2,245
Operating Income/(Loss)	151			39			(104		)	—			86
Other (Expense)/Income
Equity in (losses)/earnings of consolidated subsidiaries	(10		)	1			121			(112		)	—
Equity in earnings of unconsolidated affiliates	4			—			—			—			4
Impairment charge on investment	(1		)	—			—			—			(1		)
Other income, net	1			2			7			—			10
Loss on debt extinguishment	—			—			(41		)	—			(41		)
Interest expense	(5		)	(21		)	(137		)	—			(163		)
Total other expense	(11		)	(18		)	(50		)	(112		)	(191		)
Income Before Income Taxes	140			21			(154		)	(112		)	(105		)
Income tax expense(benefit)	67			(27		)	(153		)	—			(113		)
Net Income/(Loss)	73			48			(1		)	(112		)	8
Less: Net income attributable to noncontrolling interest	—			9			—			—			9
Net Income/(Loss) attributable to NRG Energy, Inc.	$	73		$	39		$	(1	)	$	(112	)	$	(1	)


(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, 2012

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
Operating Revenues							(In millions)
Total operating revenues	$	6,058		$	353		$	—		$	(52	)	$	6,359
Operating Costs and Expenses
Cost of operations	4,478			178			7			(45		)	4,618
Depreciation and amortization	647			48			8			—			703
Selling, general and administrative	421			36			231			(7		)	681
Acquisition-related transaction and integration costs	—			—			18			—			18
Development costs	—			—			26			—			26
Total operating costs and expenses	5,546			262			290			(52		)	6,046
Operating Income/(Loss)	512			91			(290		)	—			313
Other (Expense)/Income
Equity in earnings/(losses) of consolidated subsidiaries	6			(11		)	463			(458		)	—
Equity in earnings of unconsolidated affiliates	6			20			—			—			26
Impairment charge on investment	(2		)	—			—			—			(2		)
Other income, net	2			4			8			—			14
Loss on debt extinguishment	—			—			(41		)	—			(41		)
Interest expense	(21		)	(60		)	(414		)	—			(495		)
Total other (expense)/income	(9		)	(47		)	16			(458		)	(498		)
Income/(Loss) Before Income Taxes	503			44			(274		)	(458		)	(185		)
Income tax expense/(benefit)	193			(122		)	(317		)	—			(246		)
Net Income	310			166			43			(458		)	61
Less: Net income attributable to noncontrolling interest	—			18			—			—			18
Net Income attributable to NRG Energy, Inc.	$	310		$	148		$	43		$	(458	)	$	43


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

For the Three Months Ended September 30, 2012

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Net Income/(Loss)	$	73		$	48		$	(1	)	$	(112	)	$	8
Other comprehensive loss, net of tax
Unrealized loss on derivatives, net	(43		)	(14		)	(54		)	68			(43		)
Foreign currency translation adjustments, net	—			—			1			—			1
Reclassification adjustment for translation gain realized upon sale of Schkopau, net	—			(11		)	—			—			(11		)
Available-for-sale securities, net	—			—			2			—			2
Other comprehensive loss	(43		)	(25		)	(51		)	68			(51		)
Comprehensive income/(loss)	30			23			(52		)	(44		)	(43		)
Less: Comprehensive income attributable to noncontrolling interest	—			9			—			—			9
Comprehensive income/(loss) attributable to NRG Energy, Inc.	30			14			(52		)	(44		)	(52		)
Dividends for preferred shares	—			—			2			—			2
Comprehensive income/(loss) available for common stockholders	$	30		$	14		$	(54	)	$	(44	)	$	(54	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

For the Nine Months Ended September 30, 2012

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Net Income	$	310		$	166		$	43		$	(458	)	$	61
Other comprehensive loss, net of tax
Unrealized loss on derivatives, net	(122		)	(33		)	(145		)	168			(132		)
Foreign currency translation adjustments, net	—			(2		)	1			—			(1		)
Reclassification adjustment for translation gain realized upon sale of Schkopau, net	—			(11		)	—			—			(11		)
Available-for-sale securities, net	—			—			2			—			2
Other comprehensive loss	(122		)	(46		)	(142		)	168			(142		)
Comprehensive income/(loss)	188			120			(99		)	(290		)	(81		)
Less: Comprehensive income attributable to noncontrolling interest	—			18			—			—			18
Comprehensive income/(loss) attributable to NRG Energy, Inc.	188			102			(99		)	(290		)	(99		)
Dividends for preferred shares	—			—			7			—			7
Comprehensive income/(loss) available for common stockholders	$	188		$	102		$	(106	)	$	(290	)	$	(106	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

September 30, 2012

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
ASSETS
Current Assets
Cash and cash equivalents	$	11		$	223		$	1,376		$	—		$	1,610
Funds deposited by counterparties	76			—			—			—			76
Restricted cash	9			212			16			—			237
Accounts receivable, net	1,027			48			—			—			1,075
Inventory	381			12			—			—			393
Derivative instruments	2,677			—			—			—			2,677
Cash collateral paid in support of energy risk management activities	98			—			—			—			98
Prepayments and other current assets	2,672			12			(2,467		)	—			217
Total current assets	6,951			507			(1,075		)	—			6,383
Net property, plant and equipment	10,026			5,757			102			(19		)	15,866
Other Assets
Investment in subsidiaries	80			(48		)	16,518			(16,550		)	—
Equity investments in affiliates	34			603			12			—			649
Notes receivable – affiliate and capital leases, less current portion	3			74			727			(726		)	78
Goodwill	1,886			—			—			—			1,886
Intangible assets, net	1,116			80			30			(38		)	1,188
Nuclear decommissioning trust fund	469			—			—			—			469
Derivative instruments	309			—			—			—			309
Other non-current assets	70			113			209			—			392
Total other assets	3,967			822			17,496			(17,314		)	4,971
Total Assets	$	20,944		$	7,086		$	16,523		$	(17,333	)	$	27,220
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	—		$	88		$	286		$	—		$	374
Accounts payable	(20		)	328			938			—			1,246
Derivative instruments	2,436			17			9			—			2,462
Deferred income taxes	262			(56		)	(191		)	—			15
Cash collateral received in support of energy risk management activities	76			—			—			—			76
Accrued expenses and other current liabilities	349			37			218			—			604
Total current liabilities	3,103			414			1,260			—			4,777
Other Liabilities
Long-term debt and capital leases	273			3,933			7,488			(726		)	10,968
Nuclear decommissioning reserve	349			—			—			—			349
Nuclear decommissioning trust liability	277			—			—			—			277
Deferred income taxes	1,352			217			(477		)	—			1,092
Derivative instruments	451			110			—			—			561
Out-of-market commodity contracts	186			6			—			(31		)	161
Other non-current liabilities	567			216			113			—			896
Total non-current liabilities	3,455			4,482			7,124			(757		)	14,304
Total liabilities	6,558			4,896			8,384			(757		)	19,081
3.625% convertible perpetual preferred stock	—			—			249			—			249
Stockholders’ Equity	14,386			2,190			7,890			(16,576		)	7,890
Total Liabilities and Stockholders’ Equity	$	20,944		$	7,086		$	16,523		$	(17,333	)	$	27,220


(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, 2012

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Cash Flows from Operating Activities
Net income	$	310		$	166		$	43		$	(458	)	$	61
Adjustments to reconcile net income to net cash provided/(used) by operating activities:
Distributions and equity in (earnings)/losses of unconsolidated affiliates and consolidated subsidiaries	(6		)	19			(285		)	280			8
Depreciation and amortization	647			48			8			—			703
Provision for bad debts	40			—			—			—			40
Amortization of nuclear fuel	29			—			—			—			29
Amortization of financing costs and debt discount/premiums	—			8			17			—			25
Loss on debt extinguishment	—			—			8			—			8
Amortization of intangibles and out-of-market commodity contracts	107			1			—			—			108
Amortization of unearned equity compensation	—			—			27			—			27
Changes in deferred income taxes and liability for uncertain tax benefits	193			(122		)	(332		)	—			(261		)
Changes in nuclear decommissioning trust liability	25			—			—			—			25
Changes in derivative instruments	360			—			—			—			360
Changes in collateral deposits supporting energy risk management activities	213			—			—			—			213
Cash provided/(used) by changes in other working capital	24			57			(369		)	—			(288		)
Net Cash Provided/(Used) by Operating Activities	1,942			177			(883		)	(178		)	1,058
Cash Flows from Investing Activities
Intercompany loans to subsidiaries	(1,686		)	416			—			1,270			—
Acquisition of businesses, net of cash acquired	—			(17		)	(23		)	—			(40		)
Capital expenditures	(183		)	(2,241		)	(50		)	—			(2,474		)
Increase in restricted cash, net	(2		)	(94		)	—			—			(96		)
Decrease in restricted cash - U.S. DOE projects	—			113			38			—			151
Increase in notes receivable	—			(20		)	(2		)	—			(22		)
Purchases of emissions allowances	(8		)	—			—			—			(8		)
Proceeds from sale of emissions allowances	8			—			—			—			8
Investments in nuclear decommissioning trust fund securities	(341		)	—			—			—			(341		)
Proceeds from sales of nuclear decommissioning trust fund securities	316			—			—			—			316
Proceeds from renewable energy grants	3			46			—			—			49
Proceeds from sale of assets	133			—			4			—			137
Other	13			(8		)	(14		)	—			(9		)
Net Cash Used by Investing Activities	(1,747		)	(1,805		)	(47		)	1,270			(2,329		)
Cash Flows from Financing Activities
Proceeds from intercompany loans	—			—			1,270			(1,270		)	—
Payment of dividends to common and preferred stockholders	—			—			(28		)	—			(28		)
Payments of intercompany dividends	(172		)	(6		)	—			178			—
Net payments for settlement of acquired derivatives that include financing elements	(65		)	—			—			—			(65		)
Sale proceeds and other contributions from noncontrolling interest in subsidiaries	—			316			—			—			316
Proceeds from issuance of long-term debt	9			1,526			1,006			—			2,541
Payment of debt issuance and hedging costs	—			(16		)	(14		)	—			(30		)
Payments for short and long-term debt	—			(51		)	(904		)	—			(955		)
Net Cash (Used)/Provided by Financing Activities	(228		)	1,769			1,330			(1,092		)	1,779
Effect of exchange rate changes on cash and cash equivalents	—			(3		)	—			—			(3		)
Net (Decrease)/Increase in Cash and Cash Equivalents	(33		)	138			400			—			505
Cash and Cash Equivalents at Beginning of Period	44			85			976			—			1,105
Cash and Cash Equivalents at End of Period	$	11		$	223		$	1,376		$	—		$	1,610


(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, 2011

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Operating Revenues
Total operating revenues	$	2,581		$	97		$	—		$	(4	)	$	2,674
Operating Costs and Expenses
Cost of operations	1,993			63			(1		)	(2		)	2,053
Depreciation and amortization	224			10			4			—			238
Impairment charge on emission allowances	160			—			—			—			160
Selling, general and administrative	102			8			61			(2		)	169
Development costs	—			—			11			—			11
Total operating costs and expenses	2,479			81			75			(4		)	2,631
Operating Income/(Loss)	102			16			(75		)	—			43
Other (Expense)/Income
Equity in earnings of consolidated subsidiaries	6			4			88			(98		)	—
Equity in earnings of unconsolidated affiliates	2			14			—			—			16
Impairment charge on investment	(3		)	—			—			—			(3		)
Other income, net	3			1			1			—			5
Loss on debt extinguishment	—			—			(32		)	—			(32		)
Interest expense	(20		)	(13		)	(131		)	—			(164		)
Total other (expense)/income	(12		)	6			(74		)	(98		)	(178		)
Income/(Loss) Before Income Taxes	90			22			(149		)	(98		)	(135		)
Income tax expense/(benefit)	11			3			(94		)	—			(80		)
Net Income/(Loss) attributable to NRG Energy, Inc.	$	79		$	19		$	(55	)	$	(98	)	$	(55	)


(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, 2011

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
Operating Revenues							(In millions)
Total operating revenues	$	6,670		$	291		$	—		$	(14	)	$	6,947
Operating Costs and Expenses
Cost of operations	4,791			194			5			(5		)	4,985
Depreciation and amortization	626			28			11			—			665
Impairment charge on emissions allowances	160			—			—			—			160
Selling, general and administrative	276			20			185			(2		)	479
Development costs	—			(1		)	33			—			32
Total operating costs and expenses	5,853			241			234			(7		)	6,321
Operating Income/(Loss)	817			50			(234		)	(7		)	626
Other Expense
Equity in earnings/(losses) of consolidated subsidiaries	21			(5		)	185			(201		)	—
Equity in earnings of unconsolidated affiliates	8			18			—			—			26
Impairment charge on investment	(495		)	—			—			—			(495		)
Other income, net	3			6			4			—			13
Loss on debt extinguishment	—			—			(175		)	—			(175		)
Interest expense	(46		)	(40		)	(418		)	—			(504		)
Total other expense	(509		)	(21		)	(404		)	(201		)	(1,135		)
Income/(Loss) Before Income Taxes	308			29			(638		)	(208		)	(509		)
Income tax expense/(benefit)	123			6			(944		)	—			(815		)
Net Income attributable to NRG Energy, Inc.	$	185		$	23		$	306		$	(208	)	$	306


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE LOSS

For the Three Months Ended September 30, 2011

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Net Income/(Loss)	$	79		$	19		$	(55	)	$	(98	)	$	(55	)
Other comprehensive loss, net of tax
Unrealized loss on derivatives, net	(94		)	(11		)	(100		)	129			(76		)
Foreign currency translation adjustments, net	—			(24		)	(3		)	—			(27		)
Available-for-sale securities, net	—			—			(1		)	—			(1		)
Other comprehensive loss	(94		)	(35		)	(104		)	129			(104		)
Comprehensive loss attributable to NRG Energy, Inc.	(15		)	(16		)	(159		)	31			(159		)
Dividends for preferred shares	—			—			2			—			2
Comprehensive loss available for common stockholders	$	(15	)	$	(16	)	$	(161	)	$	31		$	(161	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE (LOSS)/INCOME

For the Nine Months Ended September 30, 2011

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Net Income	$	185		$	23		$	306		$	(208	)	$	306
Other comprehensive loss, net of tax
Unrealized loss on derivatives, net	(232		)	(13		)	(228		)	248			(225		)
Foreign currency translation adjustments, net	—			(4		)	(1		)	—			(5		)
Available-for-sale securities, net	—			—			(2		)	—			(2		)
Defined benefit plan	1			—			—			—			1
Other comprehensive loss	(231		)	(17		)	(231		)	248			(231		)
Comprehensive (loss)/income attributable to NRG Energy, Inc.	(46		)	6			75			40			75
Dividends for preferred shares	—			—			7			—			7
Comprehensive (loss)/income available for common stockholders	$	(46	)	$	6		$	68		$	40		$	68


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

December 31, 2011



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
ASSETS
Current Assets
Cash and cash equivalents	$	44		$	85		$	976		$	—		$	1,105
Funds deposited by counterparties	258			—			—			—			258
Restricted cash	8			231			53			—			292
Accounts receivable-trade, net	789			45			—			—			834
Inventory	300			8			—			—			308
Derivative instruments	4,222			—			—			(6		)	4,216
Cash collateral paid in support of energy risk management activities	311			—			—			—			311
Prepayments and other current assets	1,229			28			(983		)	(1		)	273
Total current assets	7,161			397			46			(7		)	7,597
Net Property, Plant and Equipment	10,456			3,116			67			(18		)	13,621
Other Assets
Investment in subsidiaries	225			491			16,169			(16,885		)	—
Equity investments in affiliates	33			607			—			—			640
Capital leases and notes receivable, less current portion	1			341			172			(172		)	342
Goodwill	1,886			—			—			—			1,886
Intangible assets, net	1,340			84			33			(38		)	1,419
Nuclear decommissioning trust fund	424			—			—			—			424
Derivative instruments	450			—			—			—			450
Other non-current assets	55			72			209			—			336
Total other assets	4,414			1,595			16,583			(17,095		)	5,497
Total Assets	$	22,031		$	5,108		$	16,696		$	(17,120	)	$	26,715
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	—		$	72		$	15		$	—		$	87
Accounts payable	(407		)	122			1,093			—			808
Derivative instruments	3,712			23			22			(6		)	3,751
Deferred income taxes	534			(51		)	(356		)	—			127
Cash collateral received in support of energy risk management activities	258			—			—			—			258
Accrued expenses and other current liabilities	371			23			247			(1		)	640
Total current liabilities	4,468			189			1,021			(7		)	5,671
Other Liabilities
Long-term debt and capital leases	264			1,999			7,654			(172		)	9,745
Nuclear decommissioning reserve	335			—			—			—			335
Nuclear decommissioning trust liability	254			—			—			—			254
Deferred income taxes	950			273			166			—			1,389
Derivative instruments	394			66			4			—			464
Out-of-market commodity contracts	208			6			—			(31		)	183
Other non-current liabilities	544			96			116			—			756
Total non-current liabilities	2,949			2,440			7,940			(203		)	13,126
Total liabilities	7,417			2,629			8,961			(210		)	18,797
3.625% Preferred Stock	—			—			249			—			249
Stockholders’ Equity	14,614			2,479			7,486			(16,910		)	7,669
Total Liabilities and Stockholders’ Equity	$	22,031		$	5,108		$	16,696		$	(17,120	)	$	26,715


(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, 2011

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Cash Flows from Operating Activities
Net income	$	185		$	23		$	306		$	(208	)	$	306
Adjustments to reconcile net income to net cash provided by operating activities:
Distributions and equity in (earnings)/losses of unconsolidated affiliates and consolidated subsidiaries	(10		)	2			1,184			(1,168		)	8
Depreciation and amortization	626			28			11			—			665
Provision for bad debts	41			—			—			—			41
Amortization of nuclear fuel	31			—			—			—			31
Amortization of financing costs and debt discount/premiums	—			5			20			—			25
Loss on debt extinguishment	—			—			58			—			58
Amortization of intangibles and out-of market commodity contracts	118			—			—			—			118
Amortization of unearned equity compensation	—			—			14			—			14
Changes in deferred income taxes and liability for uncertain tax benefits	123			6			(958		)	—			(829		)
Changes in nuclear decommissioning trust liability	20			—			—			—			20
Changes in derivative instruments	(199		)	1			(3		)	—			(201		)
Changes in collateral deposits supporting energy risk management activities	5			2			—			—			7
Impairment charge on investment	481			—			—			—			481
Impairment charge on emission allowance	160			—			—			—			160
Cash (used)/provided by changes in other working capital	(1,182		)	211			728			7			(236		)
Net Cash Provided by Operating Activities	399			278			1,360			(1,369		)	668
Cash Flows from Investing Activities
Intercompany loans to subsidiaries	(191		)	—			(486		)	677			—
Acquisition of business, net of cash acquired	—			(91		)	(261		)	—			(352		)
Capital expenditures	(295		)	(1,027		)	(33		)	—			(1,355		)
Increase in restricted cash, net	(54		)	(38		)	—			—			(92		)
Increase in restricted cash - U.S. DOE projects	—			(254		)	(62		)	—			(316		)
Decrease in notes receivable	—			27			—			—			27
Purchase of emission allowances	(27		)	—			—			—			(27		)
Proceeds from sale of emission allowances	6			—			—			—			6
Investments in nuclear decommissioning trust fund securities	(314		)	—			—			—			(314		)
Proceeds from sales of nuclear decommissioning trust fund securities	294			—			—			—			294
Proceeds from sale of assets	14			—			—			—			14
Investments in unconsolidated affiliates	(1		)	(16		)	—			—			(17		)
Other	(11		)	(8		)	(10		)	—			(29		)
Net Cash Used by Investing Activities	(579		)	(1,407		)	(852		)	677			(2,161		)
Cash Flows from Financing Activities
Proceeds from intercompany loans	38			448			191			(677		)	—
Payment of dividends to preferred stockholders	—			—			(7		)	—			(7		)
Payment of intercompany dividends	(65		)	(1,304		)	—			1,369			—
Payment for treasury stock	—			—			(378		)	—			(378		)
Net payment for settlement of acquired derivatives that include financing elements	(61		)	—			—			—			(61		)
Proceeds from issuance of long-term debt	116			798			4,796			—			5,710
Decrease in restricted cash supporting funded letter of credit	—			1,300			—			—			1,300
Payment for settlement of funded letter of credit	—						(1,300		)	—			(1,300		)
Proceeds from issuance of common stock	—			—			2			—			2
Payment of debt issuance and hedging costs	—			(41		)	(108		)	—			(149		)
Payments for short and long-term debt	—			(77		)	(5,373		)	—			(5,450		)
Net Cash Provided/(Used) by Financing Activities	28			1,124			(2,177		)	692			(333		)
Effect of exchange rate changes on cash and cash equivalents	—			2			—			—			2
Net Decrease in Cash and Cash Equivalents	(152		)	(3		)	(1,669		)	—			(1,824		)
Cash and Cash Equivalents at Beginning of Period	168			111			2,672			—			2,951
Cash and Cash Equivalents at End of Period	$	16		$	108		$	1,003		$	—		$	1,127


(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 NRG'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, 2012, and 2011. Also refer to NRG's Annual Report on Form 10-K for the year ended December 31, 2011, or 2011 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. As described in Note 12, Segment Reporting, NRG updated its segment structure to reflect how management currently makes its financial decisions and allocates resources, based on the Retail businesses, conventional power generation, alternative energy businesses and corporate activities.

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 environmental and regulatory 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 an integrated wholesale power generation and retail electricity company that aspires to be a leader in the way the industry and consumers think about, use, produce, and deliver energy and energy services in major competitive power markets in the United States. First, NRG is a wholesale power generator engaged in the ownership and operation of power generation facilities; the trading of energy, capacity and related products; and the transacting in and trading of fuel and transportation services. Second, NRG is a retail electricity company engaged in the supply of electricity, energy services, and cleaner energy products to retail electricity customers in deregulated markets through its Retail businesses. Finally, NRG is focused on the deployment and commercialization of potential disruptive clean energy technologies, like electric vehicles, Distributed Solar and smart meter technology, which have the potential to change the nature of the power supply industry.

NRG's Business Strategy

NRG's business strategy is intended to maximize stockholder 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 strategy is designed to enhance the Company's core business of competitive power generation and mitigate the risk of declining power prices. The Company expects to become a leading provider of sustainable energy solutions that promotes national energy security, while utilizing the Company's Retail businesses to complement and advance both initiatives.

The Company's core business is focused on: (i) excellence in safety and operating performance of its existing assets; (ii) serving the energy needs of end-use residential, commercial and industrial customers in the Company's core markets with a retail energy product that is differentiated either by premium service (Reliant), sustainability (Green Mountain Energy) or loyalty/affinity programs (Energy Plus); (iii) optimal hedging of baseload generation and retail load operations, while retaining optionality on the Company's peaking facilities; (iv) repowering of power generation assets at premium sites; (v) investment in, and deployment of, alternative energy technologies both in its wholesale and, particularly, in and around its Retail businesses and their customers; (vi) pursuing selective acquisitions, joint ventures, divestitures and investments; and (vii) engaging in a proactive capital allocation plan focused on achieving the regular return of and on stockholder capital within the dictates of prudent balance sheet management.

Moreover, the Company believes that the American energy industry is going to be increasingly impacted by the long-term societal trend towards sustainability which is both generational and irreversible. This trend is further influenced by the information technology-driven revolution, which has enabled greater and easier personal choice in other sectors of the consumer economy and will do the same in the American energy sector over the years to come. As a result, energy consumers will have increasing personal control over from whom they buy their energy, how that energy is generated and used and what environmental impact these individual choices will have. The Company's initiatives in this area of future growth are focused on: (i) renewable generation, with a concentration in solar; (ii) electric vehicle ecosystems; (iii) customer-facing energy products and services including smart grid services, nationwide retail green electricity, unique retail sales channels involving loyalty and affinity programs and custom design, reliability services; and (iv) the construction of other forms of on-site clean power generation. The Company's advances in each of these areas are driven by select acquisitions, joint ventures, and investments that are more fully described in Item 1, Business - New and On-going Company Initiatives and Development Projects of the Company's 2011 Form 10-K, and this Form 10-Q.

Pending Acquisition

On July 20, 2012, the Company entered into the Merger Agreement to acquire GenOn Energy, Inc., or GenOn. GenOn, a generator of wholesale electricity, has baseload, intermediate and peaking power generation facilities using coal, natural gas and oil, totaling approximately 22,700 MW. The Company will issue, as consideration for the acquisition, 0.1216 shares of NRG common stock for each outstanding share of GenOn, including restricted stock units outstanding, on the acquisition date, except for fractional shares which will be paid in cash. Based upon total GenOn shares outstanding as of September 30, 2012, the Company expects to issue approximately 94 million shares of NRG common stock, or 29% of total common shares outstanding following the closing of the transaction.

The Merger Agreement contains customary representations, warranties and covenants of NRG and GenOn, including, among others, covenants (a) to conduct their respective businesses in the ordinary course during the interim period between the execution of the Merger Agreement and completion of the merger, (b) not to engage in certain material transactions during the interim period except with the consent of the other party, (c) that NRG will convene and hold a meeting of its stockholders to consider and vote upon the approval of the issuance of NRG common stock in the merger and the approval and adoption of the charter amendment to allow the size of NRG's Board of Directors to be increased to 16 members in connection with the closing, (d) that GenOn will convene and hold a meeting of its stockholders to consider and vote upon the adoption of the Merger Agreement, and (e) that the parties use their respective reasonable best efforts to take all actions necessary to obtain all governmental and regulatory approvals and consents.

On September 21, 2012, the U.S. DOJ and the Federal Trade Commission granted early termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. On October 25, 2012, the PUCT approved the merger. Additionally, the 90-day prior notice period to the CPUC required under California law expired on October 31, 2012.

The merger remains subject to the satisfaction or waiver of other closing conditions, including approval by the stockholders of both companies and regulatory approvals by the FERC and the NYPSC. Additionally, the companies have requested a threshold determination by the NRC that its approval is not required. The acquisition is expected to close by the first quarter of 2013.

The combined company, which will retain the name NRG Energy, Inc., will become the largest competitive power generation company in the United States with approximately 47,000 MW of fossil fuel, nuclear, solar and wind capacity across the merit order in major competitive energy markets across the United States. In 2011, the combined fleet generated approximately 105 terawatt-hours of electricity. Expected synergies include cost and operational efficiency synergies, interest savings, reduced liquidity and collateral requirements, and a greater operational scale, which will enhance the combined company's ability to revitalize its generation fleet and optimize portfolio value.

Environmental Matters

Environmental Regulatory Landscape

In 2011, a number of U.S. EPA air regulations were finalized providing more clarity to the impact on electric generating units. A number of regulations with the potential for impact are still in development or under review by the U.S. EPA: New Source Performance Standards, or NSPS, for Greenhouse Gases, or GHGs, National Ambient Air Quality Standards, or NAAQS, revisions, coal combustion byproducts, and once-through cooling. While most of these regulations have been considered for some time, the outcomes and any resulting impact on NRG cannot be fully predicted until the rules are finalized. The timing and stringency of these regulations will contribute to a framework for the retrofit of existing fossil plants and deployment of new, cleaner technologies in the next decade. See discussion below for more detail.

Air — The U.S. EPA released the Cross-State Air Pollution Rule, or CSAPR, on July 7, 2011, with additional proposed updates on October 6, 2011. CSAPR was scheduled to replace the Clean Air Interstate Rule, or CAIR, on January 1, 2012. It was designed to bring states into attainment with PM 2.5 and ozone NAAQS, reducing SO₂ and NO_x emissions from power plants. The U.S. Court of Appeals for the District of Columbia Circuit stayed the rule on December 30, 2011, pending resolution of the numerous petitions for judicial review and leaving CAIR in effect during the stay.

On August 21, 2012, the court released their finding and CSAPR was vacated. The Court found that CSAPR violated federal law in that CSAPR requires states to reduce emissions more than their own significant contributions and the EPA wanted states to implement a Federal Implementation Plan without allowing for states to implement their own State Implementation Plans. CAIR will remain in place until EPA promulgates another regulation to replace it. The Company believes the Court decision is not material to NRG.

On February 16, 2012, the U.S. EPA finalized MATS, to control emissions of hazardous air pollutants from coal and oil fired electric generating units. Requirements include meeting the standards for mercury, acid gases, and certain metals (such as particulate matter) by April 16, 2015 on a plant wide basis with the potential for a one year extension. In April 2012, the rule was challenged on a number of issues by some states and industrial representatives. The appeal will be heard before the D.C. Circuit. NRG does not anticipate any plant impairments or capital expenditures beyond the current environmental capital expenditures schedule.

The U.S. EPA published the proposed New Source Performance Standards, or NSPS, for GHGs on April 13, 2012. The new standard, 1,000 tons of CO₂ per MWh gross, applies only to new electric generating units greater than 25 MW and provides averaging options for new units expected to install carbon capture. An exclusion for existing units minimizes the impact to NRG's coal plants.

On July 3, 2012, the EPA finalized the continued use of modified trigger levels through 2016 for GHG emissions in the Tailoring Rule. This rule maintains the current level at which projects must be permitted. While most repowering projects still trigger the permitting, the higher limit provides relief to smaller projects like the installation of back-end controls to meet other regulations.

Regulatory Matters

As operators of power plants and participants in wholesale and retail energy markets, certain NRG entities are subject to regulation by various federal and state government agencies. These include the Commodities Futures Trading Commission, or CFTC, the FERC, the NRC, and the PUCT, as well as other public utility commissions in certain states where NRG's generating, thermal, or distributed generation assets are located. In addition, NRG is subject to the market rules, procedures and protocols of the various ISO markets in which it participates. Likewise, certain NRG entities participating in the retail markets are subject to rules and regulations established by the states in which NRG entities are licensed to sell at retail. NRG must also comply with the mandatory reliability requirements imposed by the North American Electric Reliability Corporation, and the regional reliability entities in the regions where the Company operates.

NRG's operations within the ERCOT footprint 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. These operations are subject to regulation by PUCT, as well as to regulation by the NRC with respect to the Company's ownership interest in STP.

Texas Region

NRC Task Force Report — On March 11, 2012, the NRC issued Tier 1 requirements in response to the Near-Term Task Force report. Specifically, the NRC issued rules governing installation of spent fuel pool instrumentation and established mitigation strategies for beyond-design-basis external events. Additionally, the NRC issued requests for information regarding the re-evaluation of seismic and flooding hazards and the development of staffing strategies necessary for responding to an extended station blackout multi-unit event. The Company has submitted the required contingency plans and the NRC accepted the proposals. The Company anticipates being able to comply in a timely manner with all announced requirements.

ERCOT System-Wide Offer Caps — At its June 26, 2012, meeting, the PUCT approved an amendment to raise the ERCOT system-wide energy and ancillary service offer cap from $3,000 to $4,500 per MWh beginning August 1, 2012. At its October 25, 2012, meeting, the PUCT approved further increases of the system-wide offer cap effective June 1, 2013 to $5,000, escalating to $7,000 on June 1, 2014, and to $9,000 on June 1, 2015. In addition, the PUCT increased the low system offer cap to the higher of $2,000 or 50 times Houston Ship Channel gas price index, triggered when ERCOT calculates a $300,000 per MW presumed net revenue recovery in a calendar year for a gas peaking unit (Peaker Net Margin), the low cap remaining in effect for the remainder of the calendar year. In future years, the Peaker Net Margin will be established as three times the cost of new entry. The ERCOT ISO is expected to shift the Power Balance Penalty Curve, or PBPC, to match these offer cap levels. An increase in the cap on electricity prices could have a material impact on NRG's retail and wholesale operations. This is expected to be overall positive to NRG as it will potentially result in increased wholesale revenues.

Over the past several months, ERCOT has implemented a number of measures intended to ensure that real-time energy prices accurately reflect supply scarcity conditions. Specific changes include requiring that energy from reliability services (such as responsive reserves and reliability unit commitments) be offered at the system-wide offer cap, implementing floor prices during the deployment of non-spinning reserve services, and shifting 500 MWs of non-spinning reserves to responsive reserves procurement by the ISO.

On June 1, 2012, the Brattle Group issued an ERCOT sponsored report on resource adequacy. The Brattle Report provides an analysis of the current ERCOT market performance and makes numerous market design recommendations designed to incent investment in additional resources in ERCOT. The report also includes five market design options for consideration to help ensure resource adequacy. The options range from maintaining the existing energy-only market design to a forward capacity market. The PUCT has initiated a new proceeding to evaluate the Brattle Group's recommendations and indicated its intention to determine whether the current reserve margin “target” should be made a market requirement. If the reserve margin is ultimately determined to be a requirement, the PUCT will provide direction to ERCOT regarding the market measures the ISO must implement to ensure the reserve margin requirement is consistently achieved. Such measures, in keeping with the Brattle Report recommended options, would be intended to improve investment incentives for new resources in the wholesale market. The PUCT is expected to make these decisions late in 2012 or early 2013.

ERCOT Voluntary Mitigation Plan — On June 18, 2012, NRG submitted a Voluntary Mitigation Plan, or VMP, which had been agreed to by PUCT Staff, and the ERCOT Independent Market Monitor. The VMP establishes a safe harbor for energy offers from NRG's units in ERCOT's real-time market. The VMP was approved by the PUCT on July 13, 2012.

Northeast Region

New England

Forward Capacity Market — On January 19, 2012, the FERC issued an order largely denying rehearing of its prior decision addressing proposed amendments submitted by ISO New England Inc. to its Forward Capacity Market, or FCM, design, as well as two pending complaints. On March 16, 2012, the Company and other generators with interests in New England appealed the FERC's decision to the DC Circuit Court of Appeals. Briefing is currently underway.

New York

New Financial Reporting Rules in New York — On March 23, 2012, the NYPSC issued an order addressing its policy of applying “lightened” regulation to wholesale generators. The order proposed to subject wholesale generators, which would include NRG entities operating in New York, to more stringent financial reporting rules, including a requirement for generators to make an annual submission of “receipts and expenditures” to the NYPSC. Parties filed comments on the proposed financial reporting forms on July 30, 2012 and the NYPSC has not yet issued a final form.

Dunkirk Power LLC Reliability Service — On March 14, 2012, Dunkirk Power LLC, or Dunkirk Power, filed a notice with the New York Department of Public Service, or DPS, of its intent to mothball the Dunkirk Station no later than September 10, 2012. The effects of the mothball on electric system reliability were reviewed by Niagara Mohawk Power Corporation, d/b/a National Grid, or NG. As a result of those studies, NG determined that the mothball of the Dunkirk Station would have a negative impact on the reliability of the New York transmission system and that portions of the Dunkirk Station may be retained for reliability purposes via a non-market compensation arrangement. On July 12, 2012, Dunkirk Power filed a Reliability Must Run, or RMR, agreement, with the FERC. On July 20, 2012, NG and Dunkirk Power agreed on the material terms for a bilateral reliability support services, or RSS, agreement and submitted those terms to the NYPSC for rate recovery in NG's rates. On August 16, 2012, the NYPSC approved terms and on August 27, 2012, Dunkirk Power and NG entered into the RSS agreement that began on September 1, 2012. Dunkirk Power has requested that the FERC defer consideration of its RMR agreement until the NYPSC appeal period with respect to the order approving the agreement terms has run.

New York City Mitigation Order — On June 21, 2012, the FERC issued the first of two anticipated orders on the New York Independent System Operator's, or NYISO's, implementation of mitigation rules designed to prevent the exercise of buyer-side market power in the In-City capacity market. The order related primarily to the appropriate modeling assumptions that the NYISO should use in determining whether new entrants are subject to mitigation and, if so, what offer floor should apply to their capacity market bids. The FERC directed the NYISO to conduct its mitigation determinations using modeling parameters comparable to those used in the demand-curve reset process. The FERC also agreed with NRG and other generators that the NYISO needs to make its mitigation determination process more transparent and ordered appropriate changes. Finally, the FERC directed the NYISO IMM to provide a report on the effectiveness of the capacity market buyer-side market power mitigation program.

In the second anticipated order issued on September 10, 2012, the FERC found that the NYISO had not properly applied its mitigation rules to two proposed in-city generation facilities totaling over 1,000 MW (owned respectively by Astoria Energy II LLC and Bayonne Energy Center, LLC - neither of which are affiliated with the Company) and required the NYISO to redo its exemption determinations for these proposed facilities based largely on the modeling procedures presented by the Company and the other in-city generators. While the FERC did not require the NYISO to redo its determinations by a date certain, the NYISO has stated that it plans to do the redetermination for the two proposed facilities by the January 13, 2013 spot auction.

Hudson Transmission Partners Capacity Market Mitigation Complaint — On August 3, 2012, Hudson Transmission Partners, or HTP, filed a complaint at the FERC regarding the ability of its transmission cable from New Jersey to New York City to participate in the NYISO capacity markets. HTP raises two primary allegations. First, HTP alleges that the NYISO inappropriately determined that its capacity sales in the NYISO monthly spot capacity auction should be subject to a bid floor. Second, HTP asserts that even if its mitigated bid does not clear the monthly spot auction, it should still receive separate reliability compensation because the emergency transfer capacity of its cable decreases the Statewide Installed Reserve Margin, providing the NYISO an alleged reliability benefit for which HTP believes it deserves compensation. HTP's unmitigated entry into the NYISO market could have a material negative impact on NRG's existing fleet in New York City by decreasing capacity prices or by decreasing the locational capacity requirement in New York City. The NYISO's answer and other comments in response to the complaint are due November 13, 2012.

South Central Region

Entergy has announced its proposal to transfer functional control of its transmission assets to the Midwest Independent Transmission System Operator, Inc., or MISO, with a proposed transfer of control in December 2013. This transfer is subject to pending regulatory approvals. To date, the Company has publicly supported the transition of Entergy into MISO, based largely on the Company's positive experience with proven Day 2 Markets. The Company has been an active participant in the stakeholder processes surrounding Entergy's integration into MISO, including the discussions involving MISO's allocation of financial transmission rights upon integration, and is working to mitigate any potential negative economic impacts of the MISO integration.

CFTC — Dodd-Frank Act Developments

Over the past months, the CFTC has voted to adopt a range of final rules under the Dodd-Frank Wall Street Reform and Consumer Protection Act, commonly known as the “Dodd-Frank Act.” The Company is reviewing the final and proposed rules that the CFTC, SEC and other federal regulators have issued or will issue under the Dodd-Frank Act, including, without limitation, the margin rules, the end-user exemption and the definitions of “swap,” “swap dealer” and “major swap participant.” The Company is also evaluating whether and how these rules may apply to its business. The Company is an end-user of swaps and does not expect that its commercial activity will result in its being designated as either a swap dealer or major swap participant.

Changes in Accounting Standards

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

Consolidated Results of Operations

The following table provides selected financial information for the Company:



	Three months ended September 30,								Nine months ended September 30,
(In millions except otherwise noted)	2012			2011			Change %		2012			2011			Change %
Operating Revenues
Energy revenue^(a)	$	626		$	465		35	%	$	1,603		$	1,592		1	%
Capacity revenue ^(a)	194			196			(1	)	557			564			(1	)
Retail revenue	1,860			1,882			(1	)	4,576			4,526			1
Mark-to-market for economic hedging activities	(377		)	81			N/A		(458		)	149			N/A
Contract amortization	(10		)	(18		)	44		(69		)	(109		)	37
Other revenues ^(b)	38			68			(44	)	150			225			(33	)
Total operating revenues	2,331			2,674			(13	)	6,359			6,947			(8	)
Operating Costs and Expenses
Generation cost of sales^(a)	694			853			(19	)	1,655			2,017			(18	)
Retail cost of sales^(a)	847			871			(3	)	2,197			2,163			2
Mark-to-market for economic hedging activities	(118		)	40			N/A		(174		)	(68		)	156
Contract and emissions credit amortization ^(c)	13			16			(19	)	32			37			(14	)
Other cost of operations	290			273			6		908			836			9
Total cost of operations	1,726			2,053			(16	)	4,618			4,985			(7	)
Depreciation and amortization	239			238			—		703			665			6
Impairment charge on emission allowances	—			160			(100	)	—			160			(100	)
Selling, general and administrative	253			169			50		681			479			42
Acquisition-related transaction and integration costs	18			—			N/A		18			—			N/A
Development costs	9			11			(18	)	26			32			(19	)
Total operating costs and expenses	2,245			2,631			(15	)	6,046			6,321			(4	)
Operating Income	86			43			100		313			626			(50	)
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates	4			16			(75	)	26			26			—
Impairment charge on investment	(1		)	(3		)	(67	)	(2		)	(495		)	(100	)
Other income, net	10			5			100		14			13			8
Loss on debt extinguishment	(41		)	(32		)	28		(41		)	(175		)	(77	)
Interest expense	(163		)	(164		)	(1	)	(495		)	(504		)	(2	)
Total other expense	(191		)	(178		)	7		(498		)	(1,135		)	(56	)
Loss before Income Tax Expense	(105		)	(135		)	N/A		(185		)	(509		)	(64	)
Income tax benefit	(113		)	(80		)	41		(246		)	(815		)	(70	)
Net Income/(Loss)	8			(55		)	(115	)	61			306			(80	)
Less: Net income attributable to noncontrolling interest	9			—			N/A		18			—			N/A
Net (Loss)/Income Attributable to NRG Energy, Inc.	$	(1	)	$	(55	)	(98	)	$	43		$	306		(86	)
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)	$	2.81		$	4.20		(33	)%	$	2.59		$	4.21		(38	)%


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


(b)	Includes unrealized trading gains and losses.


(c)	Includes amortization of SO₂ and NO_xcredits and excludes amortization of Regional Greenhouse Gas Initiative, or RGGI, credits.

N/A - Not Applicable

Management’s discussion of the results of operations for the three months ended September 30, 2012, and 2011

Income/(Loss) before income tax expense — The pre-tax loss of $105 million for the three months ended September 30, 2012, compared to a pre-tax loss of $135 million for the three months ended September 30, 2011, primarily reflects:


•	in the current year, a $164 million increase in Conventional Generation gross margin, a $87 million increase in Retail gross margin, and a $45 million increase in Alternative Energy gross margin; offset by


•	a $118 million increase in operating costs primarily from increased selling, general and administrative expenses and acquisition-related transaction and integration costs,


•	a $300 million decrease in net mark-to-market results from economic hedging activities, and


•	a $160 million impairment charge on emissions allowances in the prior year.

Net income — The increase in net income of $63 million primarily reflects the drivers discussed as well as an income tax benefit for the three months ended September 30, 2012, of $113 million, compared with an income tax benefit of $80 million in the comparable period.

Conventional Generation gross margin

The following is a discussion of gross margin for NRG's Conventional Generation businesses, adjusted to eliminate intersegment activity, primarily with the Retail businesses.



	Three months ended September 30, 2012
	Conventional Generation
(In millions except otherwise noted)	Texas			Northeast			South Central			West			Other			Subtotal			Alternative Energy		Eliminations/Corporate			Consolidated Total
Energy revenue	$	767		$	183		$	196		$	43		$	4		$	1,193		$	54	$	(621	)	$	626
Capacity revenue	27			84			59			31			5			206			—		(12		)	194
Other revenue	(16		)	5			(3		)	4			59			49			1		(12		)	38
Generation revenue	778			272			252			78			68			1,448			55		$	(645	)	$	858
Generation cost of sales	(306		)	(145		)	(187		)	(35		)	(26		)	(699		)	—		$	5		$	(694	)
Generation gross margin	$	472		$	127		$	65		$	43		$	42		$	749		$	55

Business Metrics
MWh sold (in thousands)	13,061			2,592			6,021			863									469
MWh generated (in thousands)	11,949			2,140			4,474			863									469
Average on-peak market power prices ($/MWh) ^(a)(b)	$	31.92		$	47.29		$	31.07		$	38.77								N/A

(a) Average on-peak market power prices calculated based on average settled market prices in the following zones: for Texas region, in ERCOT - Houston and ERCOT - North; for Northeast region, in NYISO - West, NYISO - New York City, ISO - NE - Mass Hub, PJM - West Hub and PJM - DPL; and for West region, in CAISO - NP15 and CAISO - SP15.
(b) Average on-peak market power prices for South Central region are calculated based on average day ahead market prices for "into Entergy" as published in the Platts Megawatt Daily report.



	Three months ended September 30, 2011
	Conventional Generation
(In millions except otherwise noted)	Texas			Northeast			South Central			West			Other			Subtotal			Alternative Energy		Eliminations/Corporate			Consolidated Total
Energy revenue	$	724		$	207		$	205		$	19		$	13		$	1,168		$	10	$	(713	)	$	465
Capacity revenue	9			79			61			33			18			200			—		(4		)	196
Other revenue	20			1			6			(2		)	50			75			—		(7		)	68
Generation revenue	753			287			272			50			81			1,443			10		$	(724	)	$	729
Generation cost of sales	(431		)	(176		)	(197		)	(9		)	(45		)	(858		)	—		$	5		$	(853	)
Generation gross margin	$	322		$	111		$	75		$	41		$	36		$	585		$	10

Business Metrics
MWh sold (in thousands)	14,429			3,191			5,749			134									251
MWh generated (in thousands)	13,990			2,611			4,488			134									251
Average on-peak market power prices ($/MWh) ^(a)(b)	$	108.89		$	59.05		$	42.53		$	40.95								N/A

(a) Average on-peak market power prices calculated based on average settled market prices in the following zones: for Texas region, in ERCOT - Houston and ERCOT - North; for Northeast region, in NYISO - West, NYISO - New York City, ISO - NE - Mass Hub, PJM - West Hub and PJM - DPL; and for West region, in CAISO - NP15 and CAISO - SP15.
(b) Average on-peak market power prices for South Central region are calculated based on average day ahead market prices for "into Entergy" as published in the Platts Megawatt Daily report.

	Three months ended September 30,
Weather Metrics	Texas			Northeast			South Central			West
2012
CDDs ^(c)	1,594			586			1,096			724
HDDs ^(c)	—			122			41			44
2011
CDDs	1,877			585			1,134			606
HDDs	—			86			44			52
30 year average
CDDs	1,485			430			997			506
HDDs	5			159			33			108

(c)

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.

Conventional Generation gross margin — increased by $164 million, including intercompany sales, during the three months ended September 30, 2012, compared to the same period in 2011, due to:



Increase in Texas region	$	150
Increase in Northeast region	16
Decrease in South Central region	(10		)
Increase in West region	2
Other ^(a)	6
	$	164


(a)	Other gross margin primarily represents revenues from the maintenance services business, which are eliminated in consolidation.

The increase in gross margin in the Texas region was driven by:



Impact of fewer unplanned outages during periods of high scarcity pricing as well as more effective hedging and trading optimization activities	$	96
Higher gross margin from a reduction in delivered fuel costs and an increase in average realized energy prices	80
Higher revenue due to additional bi-lateral contracts with load serving entities and contracts with our Retail businesses	18
Change in unrealized trading activities	(28		)
Lower gross margin from a decrease in coal generation driven by higher outages in 2012	(11		)
Other	(5		)
	$	150

The increase in gross margin in the Northeast region was driven by:



Higher gross margin from favorable pricing on certain load-serving contracts, as well as additional load contracts with our Retail businesses	$	5
Increase in capacity revenue due to higher cleared auction prices in PJM	4
Change in unrealized trading activities and other	7
	$	16

The decrease in gross margin in the South Central region was driven by:



Lower gross margin from a decrease in average realized prices	$	(20	)
Lower gross margin from a decrease in coal generation	(5		)
Higher gross margin from higher utilization of gas generation due to lower gas prices and higher overall sales volumes	33
Change in unrealized trading activities and other	(18		)
	$	(10	)

The increase in gross margin in the West region was driven by:



Change in unrealized trading activities	$	6
Decrease in gross margin due to a decrease in realized prices, offset in part by increased run time at Encina driven by competitor's plant outages in the region	(2		)
Decreased capacity revenue due to lower prices for Encina	(2		)
	$	2

Retail gross margin

The following is a detailed discussion of retail gross margin for NRG's Retail business segment.

Selected Income Statement Data



	Three months ended September 30,
(In millions except otherwise noted)	2012		2011
Operating Revenues
Mass revenues	$	1,201	$	1,198
Commercial and Industrial revenues	605		598
Supply management revenues	55		88
Retail operating revenues ^(a)(b)	1,861		1,884
Retail cost of sales ^(c)	1,477		1,587
Retail gross margin	$	384	$	297

Business Metrics
Electricity sales volume — GWh
Mass	9,838		9,729
Commercial and Industrial ^(d)	8,495		8,014
Electricity sales volume — GWh
Texas	16,493		17,413
All other regions	1,840		330
Average retail customers count (in thousands, metered locations)
Mass ^(e)	2,052		1,773
Commercial and Industrial ^(d)	117		87
Retail customers count (in thousands, metered locations)
Mass ^(e)	2,073		1,788
Commercial and Industrial ^(d)	119		87

Weather Metrics
CDDs ^(f)	1,708		2,050
HDDs^(f)	—		—


(a)	Includes customers of the Texas General Land Office for which the Company provides services, as well as sales to utility partner customers.


(b)	Includes intercompany sales of $1 million and $2 million, respectively, representing sales from Retail to the Texas region.


(c)	Includes intercompany purchases of $630 million and $716 million, respectively.


(d)	Includes customers of the Texas General Land Office for which the Company provides services.


(e)	Excludes utility partner customers.


(f)	The CDDs/HDDs amounts are representative of the Coast and North Central Zones within the ERCOT market in which Retail serves its customer base.


•	Retail gross margin — Retail gross margin increased $87 million for the three months ended September 30, 2012, compared to the same period in 2011, driven by:



Acquisition of Energy Plus in September 2011	$	41
Favorable impact of fewer scarcity price increases during times of excessive load compared to prior year, offset by generally milder weather in 2012	40
Increase in usage and customer count	19
Decrease in unit margins, driven primarily by weather-related risk management activities, as well as lower pricing and lower supply costs on acquisitions and renewals	(13		)
	$	87

•

Trends — Customer counts increased by approximately 63,000 since June 30, 2012, which was primarily due to marketing efforts in ERCOT and new territories. While cooling and heating degree days in both periods resulted in higher than normal customer usage, weather in 2011 was warmer than in 2012. The weather resulted in higher customer usage of 1% and 13% in 2012 and 2011, respectively, when compared to ten-year normal weather. In addition, there were increases in Texas in Transmission and Distribution Service Provider rates that will remain in effect for several years. These costs are passed through to Retail customers.

Alternative Energy gross margin

NRG's Alternative Energy business segment, which is comprised mainly of the solar and wind businesses, had gross margin of $55 million for the three months ended September 30, 2012, compared to gross margin of $10 million for the same period in 2011. The increase in gross margin primarily resulted from the addition of the Roadrunner facility, which began commercial operations in late 2011, the addition of the first 230 MW of Agua Caliente, which reached commercial operations in 2012, and an increase in gross margin from Distributed Solar.

Mark-to-market for Economic Hedging Activities

Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges and ineffectiveness on cash flow hedges. Total net mark-to-market results decreased by $300 million during the three months ended September 30, 2012, compared to the same period in 2011.

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



	Three months ended September 30, 2012
	Retail			Texas			Northeast		South Central		West		Alternative Energy		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	$	(2	)	$	(2	)	$	1	$	10	$	5	$	—	$	(19	)	$	(7	)
Net unrealized gains/(losses) on open positions related to economic hedges	13			101			1		2		4		1		(492		)	(370		)
Total mark-to-market gains/(losses) in operating revenues	$	11		$	99		$	2	$	12	$	9	$	1	$	(511	)	$	(377	)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(103	)	$	3		$	2	$	1	$	—	$	—	$	19		$	(78	)
Reversal of gain positions acquired as part of the Reliant Energy and Green Mountain Energy acquisitions	(15		)	—			—		—		—		—		—			(15		)
Net unrealized (losses)/gains on open positions related to economic hedges	(308		)	9			7		11		—		—		492			211
Total mark-to-market (losses)/gains in operating costs and expenses	$	(426	)	$	12		$	9	$	12	$	—	$	—	$	511		$	118


(a)	Represents the elimination of the intercompany activity between the Retail businesses and the Conventional Generation regions and Alternative Energy.



	Three months ended September 30, 2011
	Retail			Texas			Northeast			South Central			West			Elimination^(a)			Total
	(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized losses on settled positions related to economic hedges	$	—		$	44		$	5		$	7		$	—		$	(33	)	$	23
Net unrealized gains/(losses) on open positions related to economic hedges	1			20			6			(6		)	(5		)	42			58
Total mark-to-market gains/(losses) in operating revenues	$	1		$	64		$	11		$	1		$	(5	)	$	9		$	81
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized gains on settled positions related to economic hedges	$	(2	)	$	(1	)	$	(1	)	$	(2	)	$	—		$	33		$	27
Reversal of gain positions acquired as part of the Reliant Energy and Green Mountain Energy acquisitions	(11		)	—			—			—			—			—			(11		)
Net unrealized (losses)/gains on open positions related to economic hedges	(23		)	4			(3		)	8			—			(42		)	(56		)
Total mark-to-market (losses)/gains in operating costs and expenses	$	(36	)	$	3		$	(4	)	$	6		$	—		$	(9	)	$	(40	)


(a)	Represents the elimination of the intercompany activity between the Retail businesses and the Conventional Generation 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, 2012, the net losses on open positions were due to increases in forward natural gas and power prices.

For the three months ended September 30, 2011, the net gains on open positions were due to a decrease in forward power and gas prices. The reversal of gain positions acquired as part of the Reliant Energy and Green Mountain Energy acquisitions were valued using forward prices on the acquisition dates. The roll-off amounts were offset by realized net losses at the settled prices and lower net 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 three months ended September 30, 2012, and 2011. The realized and unrealized financial and physical trading results are included in operating revenue. The Company's trading activities are subject to limits within the Company's Risk Management Policy.



	Three months ended September 30,
(In millions)	2012			2011
Trading gains/(losses)
Realized	$	40		$	(43	)
Unrealized	(18		)	8
Total trading gains/(losses)	$	22		$	(35	)

Contract Amortization Revenue

Contract amortization represents the roll-off of in-market customer contracts valued under purchase accounting and the favorable change of $8 million as compared to the prior period in 2011 related primarily to lower contract amortization for Reliant Energy and Green Mountain Energy of $5 million and $3 million, respectively.

Other Operating Costs



	Retail		Texas		Northeast		South Central		West		Other		Alternative Energy		Eliminations/Corporate			Total
	(In millions)
Three months ended September 30, 2012	$	66	$	116	$	56	$	22	$	11	$	22	$	7	$	(10	)	$	290
Three months ended September 30, 2011	$	56	$	113	$	57	$	25	$	8	$	18	$	5	$	(9	)	$	273

Other operating costs increased by $17 million for the three months ended September 30, 2012, compared to the same period in 2011, due to:



Increase in Retail operations and maintenance expense	$	11
Increase in Texas region operations and maintenance expense	3
Other	3
	$	17


◦	Retail operations and maintenance expense — increased primarily due to the acquisition of Energy Plus in September 2011 as well as increased customer billing costs from an increase in customer counts.


◦	Texas operations and maintenance — increased due to maintenance spending and outage work in 2012 at S.R. Bertron to return two units to service and related to timing of maintenance work in 2012.

Impairment Charge on Emission Allowances

As described in Note 24, Environmental Matters, to the Company's 2011 Form 10-K, NRG recorded an impairment charge of $160 million in the three months ended September 30, 2011, on the Company's Acid Rain Program SO₂ emission allowances, which were recorded as an intangible asset on the Company's balance sheet. The impairment charge reflects the write-off of the value of emission allowances in excess of those required for compliance with the Acid Rain Program.

Selling, General and Administrative Expenses

Selling, general and administrative expenses increased by $84 million for the three months ended September 30, 2012, compared to the same period in 2011, which was due primarily to the following:

◦Selling, general and administrative costs of $27 million for Energy Plus which was acquired in September 2011;


◦	Increase in marketing costs of $13 million associated with customer growth efforts and new market expansion by corporate and the Retail businesses;

◦Increase in labor costs of $4 million for additional solar projects and acquired Distributed Solar businesses;

◦The impact of a settlement with the EPA regarding LaGen of $14 million; and


◦	Additional costs associated with new business initiatives of $6 million, consulting, legal and other costs of $8 million and $12 million of additional labor costs.

Acquisition-related Transaction and Integration Costs

As previously announced, NRG entered into an agreement to acquire GenOn, which is expected to close by the first quarter of 2013. In connection with the pending transaction, NRG has incurred transaction and integration costs of $18 million in the three months ended September 30, 2012, consisting primarily of financial consulting fees and legal expenses.

Equity in Earnings of Unconsolidated Affiliates

NRG's equity earnings from unconsolidated affiliates were $4 million for the three months ended September 30, 2012, compared to $16 million for the same period in 2011 primarily due to changes in the fair value of Sherbino's forward gas contract as well as additional equity losses from investments in emerging energy technology companies.

Impairment Charge on Investment

As discussed in more detail in Note 4, Nuclear Innovation North America LLC Developments, Including Impairment Charge, of the Company's 2011 Form 10-K, the devastating March 2011 earthquake and tsunami in Japan, which in turn triggered a nuclear incident at the Fukushima Daiichi Nuclear Power Station, caused NRG to evaluate its investment in NINA for impairment. Consequently, NRG deconsolidated its investment in NINA and took an impairment charge in the first quarter of 2011 equal to the balance of its investment in NINA, or $481 million. To support NINA's ongoing work, NRG contributed an additional $3 million into NINA during the third quarter of 2011, which NRG also expensed as an impairment charge.

Loss on Debt Extinguishment

A loss on debt extinguishment of the 2017 Senior Notes of $41 million was recorded in the three months ended September 30, 2012, while a loss on debt extinguishment for the Senior Credit Facility of $32 million was recorded in the three months ended September 30, 2011. These losses primarily consisted of the premiums paid on redemption and the write-off of previously deferred financing costs.

Interest Expense

NRG's interest expense decreased by $1 million compared to the same period in 2011 due to the following:



Increase/(decrease) in interest expense	(In millions)
Increase from additional project financings	$	17
Decrease for higher capitalized interest	(14		)
Other	(4		)
Total	$	(1	)

Income Tax Benefit

For the three months ended September 30, 2012, NRG recorded an income tax benefit of $113 million on pre-tax loss of $105 million. For the same period in 2011, NRG recorded an income tax benefit of $80 million on a pre-tax loss of $135 million. The effective tax rate was 107.6% and 59.3% for the three months ended September 30, 2012, and 2011, respectively.

For the three months ended September 30, 2012, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the generation of ITCs from the Company's Agua Caliente solar project in Arizona and PTCs generated from certain Texas wind facilities.

For the three months ended September 30, 2011, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to a reduction in the valuation allowance.

Management’s discussion of the results of operations for the nine months ended September 30, 2012, and 2011

Loss before income tax expense — The pre-tax loss of $185 million for the nine months ended September 30, 2012, compared to a pre-tax loss of $509 million for the nine months ended September 30, 2011, primarily reflects:


•	in the current year, a decrease in operating income of $313 million as compared to the prior year period, which reflects:


◦	a decrease from net mark-to-market results for economic hedging activities of $501 million; and


◦	increased operating costs of $324 million including operations and maintenance expense, depreciation and amortization, selling, general and administrative costs and acquisition-related transaction and integration costs; offset by:


◦	an increase in gross margin of $342 million comprised of an increase in Conventional Generation gross margin of $127 million, an increase in Retail gross margin of $134 million and an increase in Alternative Energy gross margin of $81 million; and


◦	in the prior year, a $160 million impairment charge on emissions allowances.


•	in addition, the prior year also reflects:

◦a $495 million loss on the impairment of NRG's investment in NINA, and


◦	a $175 million loss on the extinguishment of the 2014 Senior Notes, the 2016 Senior Notes and the Senior Credit Facility.

Net income — The decrease in net income of $263 million primarily reflects the drivers discussed above offset by an income tax benefit for the nine months ended September 30, 2012, of $246 million, which reflects the impact of the ITC for Agua Caliente, compared with an income tax benefit of $815 million in the comparable period, which primarily reflects the resolution of the federal tax audit in June 2011 and the related recognition of previously uncertain tax benefits.

Conventional Generation gross margin

The following is a discussion of gross margin for NRG's Conventional Generation businesses, adjusted to eliminate intersegment activity, primarily with the Retail businesses.



	Nine months ended September 30, 2012
	Conventional Generation
(In millions except otherwise noted)	Texas			Northeast			South Central			West			Other			Subtotal			Alternative Energy		Eliminations/Corporate			Consolidated Total
Energy revenue	$	1,866		$	370		$	436		$	85		$	38		$	2,795		$	112	$	(1,304	)	$	1,603
Capacity revenue	64			211			181			91			40			587			—		(30		)	557
Other revenue	4			14			(7		)	4			185			200			2		(52		)	150
Generation revenue	1,934			595			610			180			263			3,582			114		$	(1,386	)	$	2,310
Generation cost of sales	(752		)	(310		)	(424		)	(63		)	(119		)	(1,668		)	—		$	13		$	(1,655	)
Generation gross margin	$	1,182		$	285		$	186		$	117		$	144		$	1,914		$	114

Business Metrics
MWh sold (in thousands)	33,935			5,494			14,699			1,618									1,434
MWh generated (in thousands)	28,796			4,286			12,733			1,618									1,434
Average on-peak market power prices ($/MWh) ^(a)(b)	$	29.43		$	40.44		$	27.59		$	31.49								N/A

(a) Average on-peak market power prices calculated based on average settled market prices in the following zones: for Texas region, in ERCOT - Houston and ERCOT - North; for Northeast region, in NYISO - West, NYISO - New York City, ISO - NE - Mass Hub, PJM - West Hub and PJM - DPL; and for West region, in CAISO - NP15 and CAISO - SP15.
(b) Average on-peak market power prices for South Central region are calculated based on average day ahead market prices for "into Entergy" as published in the Platts Megawatt Daily report.



	Nine months ended September 30, 2011
	Conventional Generation
(In millions except otherwise noted)	Texas			Northeast			South Central			West			Other			Subtotal			Alternative Energy		Eliminations/Corporate			Consolidated Total
Energy revenue	$	1,991		$	503		$	435		$	28		$	43		$	3,000		$	32	$	(1,440	)	$	1,592
Capacity revenue	19			228			183			89			54			573			—		(9		)	564
Other revenue	65			14			14			3			148			244			1		(20		)	225
Generation revenue	2,075			745			632			120			245			3,817			33		$	(1,469	)	$	2,381
Generation cost of sales	(995		)	(449		)	(432		)	(14		)	(140		)	(2,030		)	—		$	13		$	(2,017	)
Generation gross margin	$	1,080		$	296		$	200		$	106		$	105		$	1,787		$	33

Business Metrics
MWh sold (in thousands)	38,057			8,127			13,223			189									914
MWh generated (in thousands)	36,348			6,522			12,147			189									914
Average on-peak market power prices ($/MWh) ^(a)(b)	$	66.81		$	57.02		$	39.93		$	37.06								N/A

(a) Average on-peak market power prices calculated based on average settled market prices in the following zones: for Texas region, in ERCOT - Houston and ERCOT - North; for Northeast region, in NYISO - West, NYISO - New York City, ISO - NE - Mass Hub, PJM - West Hub and PJM - DPL; and for West region, in CAISO - NP15 and CAISO - SP15.
(b) Average on-peak market power prices for South Central region are calculated based on average day ahead market prices for "into Entergy" as published in the Platts Megawatt Daily report.

	Nine months ended September 30,
Weather Metrics	Texas			Northeast			South Central			West
2012
CDDs ^(c)	2,843			752			1,761			844
HDDs ^(c)	816			3,317			1,564			1,935
2011
CDDs	3,197			749			1,796			676
HDDs	1,171			3,978			2,157			2,193
30 year average
CDDs	2,434			534			1,486			663
HDDs	1,220			4,126			2,246			2,164

(c)

Conventional Generation gross margin — increased by $127 million, including intercompany sales, during the nine months ended September 30, 2012, compared to the same period in 2011, due to:



Increase in Texas region	$	102
Decrease in Northeast region	(11		)
Decrease in South Central region	(14		)
Increase in West region	11
Other ^(a)	39
	$	127


(a)	Other gross margin primarily represents revenues from the maintenance services business, which are eliminated in consolidation.

The increase in gross margin in the Texas region was driven by:



Impact of fewer unplanned outages during periods of high scarcity pricing as well as more effective hedging and trading optimization activities	$	96
Higher gross margin driven by higher average realized energy prices and a decrease in delivered fuel costs	54
Higher revenue due to additional bi-lateral contracts with load serving entities and contracts with our Retail businesses	45
Lower gross margin from a decrease in coal and nuclear generation driven by higher unplanned outage hours in 2012	(54		)
Change in unrealized trading activities	(42		)
Other	3
	$	102

The decrease in gross margin in the Northeast region was driven by:



Lower gross margin from coal plants due to a 47% decrease in generation, resulting from the region's power generation switching from coal to gas plants	$	(16	)
Lower gross margin from coal plants due to a 7% increase in delivered coal prices	(11		)
Lower capacity revenue due to 5% lower realized prices, due mainly to lower cleared auction prices in PJM, and slightly lower volumes, offset in part by additional revenue from the Dunkirk RSS contract.	(16		)
Higher gross margin from favorable pricing on certain load-serving contracts, as well as additional load contracts with our Retail businesses	34
Other	(2		)
	$	(11	)

The decrease in gross margin in the South Central region was driven by:



Lower gross margin from a decrease in coal generation as a result of lower gas prices	$	(43	)
Lower gross margin from a decrease in average realized merchant prices	(61		)
Higher gross margin from higher utilization of gas generation due to lower gas prices and higher overall sales volumes	125
Change in unrealized trading activities and other	(35		)
	$	(14	)

The increase in gross margin in the West region was driven by:



Higher gross margin from increased run time at Encina driven by competitor's plant outages in the region and increased run time at the remaining plants in the region	$	11
Higher capacity margin due to the recognition of contingent rent for Long Beach	5
Decreased capacity revenue due to lower prices for Encina	(3		)
Decrease in fuel sales compared to 2011	(2		)
	$	11

Retail gross margin

The following is a detailed discussion of retail gross margin for NRG's Retail business segment.

Selected Income Statement Data



	Nine months ended September 30,
(In millions except otherwise noted)	2012		2011
Operating Revenues
Mass revenues	$	2,902	$	2,795
Commercial and Industrial revenues	1,557		1,581
Supply management revenues	120		154
Retail operating revenues ^(a)(b)	4,579		4,530
Retail cost of sales ^(c)	3,521		3,606
Retail gross margin	$	1,058	$	924

Business Metrics
Electricity sales volume — GWh
Mass	23,301		22,198
Commercial and Industrial ^(d)	22,459		21,521
Electricity sales volume — GWh
Texas	41,703		43,077
All other regions	4,057		642
Average retail customers count (in thousands, metered locations)
Mass ^(e)	2,021		1,780
Commercial and Industrial ^(d)	113		90
Retail customers count (in thousands, metered locations)
Mass ^(e)	2,073		1,788
Commercial and Industrial ^(d)	119		87

Weather Metrics
CDDs ^(f)	3,112		3,516
HDDs^(f)	613		987


(a)	Includes customers of the Texas General Land Office for which the Company provides services, as well as sales to utility partner customers.


(b)	Includes intercompany sales of $3 million and $4 million, respectively, representing sales from Retail to the Texas region .


(c)	Includes intercompany purchases of $1,324 million and $1,443 million, respectively.


(d)	Includes customers of the Texas General Land Office for which the Company provides services.


(e)	Excludes utility partner customers.


(f)	The CDDs/HDDs amounts are representative of the Coast and North Central Zones within the ERCOT market in which Retail serves its customer base.


•	Retail gross margin — Retail gross margin increased $134 million for the nine months ended September 30, 2012, compared to the same period in 2011, driven by:



Acquisition of Energy Plus in September 2011	$	105
Increase in usage and customer count	38
Unfavorable impact of weather-related risk management activities	(25		)
Favorable impact of fewer scarcity price increases during times of excessive load compared to prior year, offset by generally milder weather in 2012	31
Decrease in unit margins driven by the impact of lower pricing and lower supply costs on acquisitions and renewals	(15		)
	$	134

•

Trends — Customer counts increased by approximately 124,000 since December 31, 2011, which was primarily due to expansion into new territories and marketing efforts. While cooling and heating degree days in both periods resulted in higher than normal customer usage, weather in 2012 was milder than in 2011. The weather resulted in higher customer usage of 4% and 13% in 2012 and 2011, respectively, when compared to ten-year normal weather. In addition, there were increases in Texas in Transmission and Distribution Service Provider rates that will remain in effect for several years. These costs are passed through to Retail customers.

Alternative Energy gross margin

NRG's Alternative Energy business segment, which is comprised mainly of the solar and wind businesses, had gross margin of $114 million for the nine months ended September 30, 2012, compared to gross margin of $33 million for the same period in 2011. The increase in gross margin primarily resulted from the addition of the Roadrunner facility, which began commercial operations in late 2011, the addition of the first 230 MW of Agua Caliente, which reached commercial operations in 2012, and an increase in gross margin from Distributed Solar.

Mark-to-market for Economic Hedging Activities

Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges and ineffectiveness on cash flow hedges. Total net mark-to-market results decreased by $501 million during the nine months ended September 30, 2012, compared to the same period in 2011.

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



	Nine months ended September 30, 2012
	Retail			Texas			Northeast			South Central			West			Alternative Energy		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	$	(5	)	$	(330	)	$	2		$	31		$	7		$	—	$	65		$	(230	)
Net unrealized gains/(losses) on open positions related to economic hedges	1			(142		)	1			(3		)	(2		)	—		(83		)	(228		)
Total mark-to-market (losses)/gains in operating revenues	$	(4	)	$	(472	)	$	3		$	28		$	5		$	—	$	(18	)	$	(458	)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses on settled positions related to economic hedges	$	112		$	12		$	8		$	3		$	—		$	—	$	(65	)	$	70
Reversal of loss positions acquired as part of the Reliant Energy and Green Mountain Energy acquisitions	5			—			—			—			—			—		—			5
Net unrealized gains/(losses) on open positions related to economic hedges	99			(47		)	(4		)	(32		)	—			—		83			99
Total mark-to-market gains/(losses) in operating costs and expenses	$	216		$	(35	)	$	4		$	(29	)	$	—		$	—	$	18		$	174


(a)	Represents the elimination of the intercompany activity between the Retail businesses and the Conventional Generation regions and Alternative Energy.



	Nine months ended September 30, 2011
	Retail			Texas			Northeast			South Central			West			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	)	$	(25	)	$	16		$	20		$	(1	)	$	17		$	26
Net unrealized gains/(losses) on open positions related to economic hedges	4			99			9			(12		)	3			20			123
Total mark-to-market gains in operating revenues	$	3		$	74		$	25		$	8		$	2		$	37		$	149
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	70		$	1		$	(5	)	$	(3	)	$	—		$	(17	)	$	46
Reversal of loss positions acquired as part of the Reliant Energy and Green Mountain Energy acquisitions	60			—			—			—			—			—			60
Net unrealized (losses)/gains on open positions related to economic hedges	(55		)	20			1			16			—			(20		)	(38		)
Total mark-to-market gains/(losses) in operating costs and expenses	$	75		$	21		$	(4	)	$	13		$	—		$	(37	)	$	68


(a)	Represents the elimination of the intercompany activity between the Retail businesses and the Conventional Generation 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, 2012, the net losses on open positions were due primarily to decreases in forward coal prices.

For the nine months ended September 30, 2011, the net gains on open positions were due to a decrease in forward power and gas prices. The reversal of loss positions acquired as part of the Reliant Energy and Green Mountain Energy acquisitions were valued using forward prices on the acquisition dates. 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, 2012, and 2011. The realized and unrealized financial and physical trading results are included in operating revenue. The Company's trading activities are subject to limits within the Company's Risk Management Policy.



	Nine months ended September 30,
(In millions)	2012			2011
Trading gains/(losses)
Realized	$	71		$	(28	)
Unrealized	(12		)	44
Total trading gains	$	59		$	16

Contract Amortization Revenue

Contract amortization represents the roll-off of in-market customer contracts valued under purchase accounting and the favorable change of $40 million, as compared to the prior period in 2011, related primarily to lower contract amortization of $26 million and $14 million for Reliant Energy and Green Mountain Energy, respectively.

Other Operating Costs



	Retail		Texas		Northeast		South Central		West		Other		Alternative Energy		Eliminations/Corporate			Total
	(In millions)
Nine months ended September 30, 2012	$	183	$	393	$	167	$	73	$	42	$	79	$	18	$	(47	)	$	908
Nine months ended September 30, 2011	$	156	$	356	$	164	$	68	$	44	$	53	$	12	$	(17	)	$	836

Other operating costs increased by $72 million for the nine months ended September 30, 2012, compared to the same period in 2011, due to:



Increase in Texas region operations and maintenance expense	$	38
Increase in Retail operations and maintenance expense	26
Increase in Alternative Energy region operations and maintenance expense	7
Decrease in Northeast region operations and maintenance expense	(8		)
Increase in property tax expense	14
Other	(5		)
	$	72


◦	Texas operations and maintenance — increased primarily due to maintenance spending and outage work in 2012 at S.R. Bertron to return two units to service, as well as timing of planned and unplanned outages in the region.


◦	Retail operations and maintenance expense — increased $12 million due to the acquisition of Energy Plus in September 2011 and increased due to additional customer billing costs from an increase in customer counts.


◦	Alternative Energy operations and maintenance expense — increased as additional solar facilities began commercial operations in 2012.


◦	Northeast operations and maintenance expense — decreased in part because the prior year reflects incremental costs associated with headcount reductions.


◦	Property tax expense — increased primarily for $11 million in the Northeast region due to a reduction in property tax benefit from the New York State Empire Zone program. The reduction reflects the criteria in determining the amount of the tax credit and the annual reduction of 20% beginning in 2012 until the expiration of the program in 2016.

Depreciation and Amortization Expense

Depreciation and amortization expense increased by $38 million for the nine months ended September 30, 2012, compared to the same period in 2011. This was primarily due to additional depreciation related to solar facilities which commenced commercial operations in late 2011 and early 2012, as well as the amortization of the intangibles acquired in connection with the acquisition of Energy Plus.

Impairment Charge on Emission Allowances

Selling, General and Administrative Expenses

Selling, general and administrative expenses increased by $202 million for the nine months ended September 30, 2012, compared to the same period in 2011, which was due primarily to the following:

◦Selling, general and administrative costs of $66 million for Energy Plus which was acquired in September 2011;

◦Expected cash payment related to the CDWR settlement of $20 million expensed during the period;

◦Transaction costs of $9 million associated with the sale of 49% of Agua Caliente;


◦	Increase in marketing costs of $40 million associated with customer growth efforts and new market expansion by corporate and the Retail businesses;

◦Increase in labor costs of $10 million for additional solar projects and acquired Distributed Solar businesses;

◦The impact of a settlement with the EPA regarding LaGen of $14 million; and


◦	Additional costs associated with new business initiatives of $11 million, consulting and legal costs of $5 million and $27 million of additional labor costs.

Acquisition-related Transaction and Integration Costs

As previously announced, NRG entered into an agreement to acquire GenOn, which is expected to close by the first quarter of 2013. In connection with the pending transaction, NRG has incurred transaction and integration costs of $18 million in the nine months ended September 30, 2012, consisting primarily of financial consulting fees and legal expenses.

Impairment Charge on Investment

As discussed in more detail in Note 4, Nuclear Innovation North America LLC Developments, Including Impairment Charge, of the Company's 2011 Form 10-K, the March 2011 earthquake and tsunami in Japan, which in turn triggered a nuclear incident at the Fukushima Daiichi Nuclear Power Station, caused NRG to evaluate its investment in NINA for impairment. Consequently, NRG deconsolidated its investment in NINA and took an impairment charge in the first quarter of 2011 equal to the balance of its investment in NINA. To support NINA's ongoing work, NRG contributed an additional $14 million into NINA during the nine months ended September 30, 2011. As a result, NRG recorded an impairment charge of $495 million in the nine months ended September 30, 2011.

Loss on Debt Extinguishment

A loss on debt extinguishment of the 2017 Senior Notes of $41 million was recorded in the nine months ended September 30, 2012, while a loss on debt extinguishment of the 2014 Senior Notes, the 2016 Senior Notes and the Senior Credit Facility of $175 million was recorded in the nine months ended September 30, 2011. These losses primarily consisted of the premiums paid on redemption and the write-off of previously deferred financing costs.

Interest Expense

NRG's interest expense decreased by $9 million for the nine months ended September 30, 2012, compared to the same period in 2011 due to the following:



Increase/(decrease) in interest expense	(In millions)
Decrease for 2014 Senior Notes and 2016 Senior Notes redeemed in 2011	$	(82	)
Increase for 2019 and 2021 Senior Notes issued in May 2011	60
Decrease for higher capitalized interest	(47		)
Increase from additional project financings	34
Increase in derivative interest expense primarily for the Alpine interest rate swaps	14
Increase for 2018 Senior Notes issued in January 2011	6
Other	6
Total	$	(9	)

Income Tax Benefit

For the nine months ended September 30, 2012, NRG recorded an income tax benefit of $246 million on a pre-tax loss of $185 million. For the same period in 2011, NRG recorded an income tax benefit of $815 million on a pre-tax loss of $509 million. The effective tax rate was 133.0% and 160.1% for the nine months ended September 30, 2012, and 2011, respectively.

For the nine months ended September 30, 2012, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the generation of ITCs from the Company's Agua Caliente solar project in Arizona and the PTCs generated from certain Texas wind facilities.

For the nine months ended September 30, 2011, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to a benefit of $633 million resulting from the resolution of the federal tax audit. The benefit is predominantly due to the recognition of previously uncertain tax benefits that were effectively settled upon audit examination for years 2004 through 2006 and that were mainly composed of net operating losses of $536 million which has been classified as capital loss carryforwards for financial statement purposes.

Liquidity and Capital Resources

Liquidity Position

As of September 30, 2012, and December 31, 2011, NRG's liquidity, excluding collateral received, was approximately $3.0 billion and $2.1 billion, respectively, comprised of the following:



(In millions)	September 30, 2012			December 31, 2011
Cash and cash equivalents	$	1,610		$	1,105
Funds deposited by counterparties	76			258
Restricted cash	237			292
Total	1,923			1,655
2011 Revolving Credit Facility availability	1,133			673
Total liquidity	3,056			2,328
Less: Funds deposited as collateral by hedge counterparties	(76		)	(258		)
Total liquidity, excluding collateral received	$	2,980		$	2,070

For the nine months ended September 30, 2012, total liquidity, excluding collateral received, increased by $910 million. The increase in the 2011 Revolving Credit Facility availability was primarily due to a $304 million reduction in letters of credit due to the sale of a 49% interest in Agua Caliente in January 2012 to MidAmerican, and the addition of the NRG Repowering credit facility in January 2012 as discussed in Note 8, Debt and Capital Leases, to this Form 10-Q. Changes in cash and cash equivalent balances are further discussed hereinafter under the heading Cash Flow Discussion. Cash and cash equivalents and funds deposited by counterparties at September 30, 2012 were predominantly held in money market funds invested in treasury securities, treasury repurchase agreements or government agency debt. As discussed in Note 8, Debt and Capital Leases, to this Form 10-Q, on October 24, 2012, NRG redeemed the remaining $270 million outstanding of the 2017 Senior Notes.

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 12 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, to fund dividends to NRG's common and preferred stockholders, and other liquidity commitments.

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, Debt and Capital Leases, to this Form 10-Q and Note 12, Debt and Capital Leases, to the Company's 2011 Form 10-K, the Company's financing arrangements consist mainly of the 2011 Senior Credit Facility, the Senior Notes, and project-related financings.

In addition, NRG has granted first liens to certain counterparties on substantially all of the Company's assets. NRG uses the first lien structure to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or MWh equivalents. To the extent that the underlying hedge positions for a counterparty are in-the-money to NRG, the counterparty would have no claim under the lien program. The lien program limits the volume that can be hedged, not the value of underlying out-of-the-money positions. The first lien program does not require NRG to post collateral above any threshold amount of exposure. Within the first 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 lien structure is not subject to unwind or termination upon a ratings downgrade of a counterparty 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 prices. As of September 30, 2012, in aggregate, the hedge portfolio under the lien was in-the-money.

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 lien structure as of September 30, 2012:



Equivalent Net Sales Secured by First Lien Structure ^(a)	2012		2013		2014		2015		2016
In MW ^(b)	2,216		1,664		1,500		550		643
As a percentage of total net baseload capacity ^(c)	33	%	25	%	23	%	8	%	10	%


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


(b)	2012 MW value consists of November through December positions only.


(c)	Net baseload capacity under the first 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 repowering and renewable development, and environmental; and (iv) corporate financial transactions including return of capital and dividend payments to stockholders.

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) margin and collateral required to participate in physical markets and commodity exchanges; (iii) timing of disbursements and receipts (i.e. buying fuel before receiving energy revenues); (iv) initial collateral for large structured transactions; and (v) collateral for project development. As of September 30, 2012, commercial operations had total cash collateral outstanding of $88 million, and $667 million outstanding in letters of credit to third parties primarily to support its commercial activities for both wholesale and retail transactions (includes a $49 million letter of credit relating to deposits at the PUCT that cover outstanding customer deposits and residential advance payments). As of September 30, 2012, total collateral held from counterparties was $76 million in cash, and $10 million of letters of credit.

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

Capital Expenditures

The following tables and descriptions summarize the Company's capital expenditures, including accruals, for maintenance, environmental, and growth investments for the nine months ended September 30, 2012, and the estimated capital expenditure and growth investments forecast for the remainder of 2012.



	Maintenance			Environmental			Growth Investments			Total
	(In millions)
Northeast	$	13		$	24		$	—		$	37
Texas	89			1			—			90
South Central	13			5			—			18
West	4			—			154			158
Other Conventional	—			—			20			20
Retail	13			—			—			13
Alternative Energy	6			—			2,563			2,569
Corporate	5			—			—			5
Total capital expenditures for the nine months ended September 30, 2012	143			30			2,737			2,910
Accrual impact, net	8			8			(452		)	(436		)
Total cash capital expenditures for the nine months ended September 30, 2012	151			38			2,285			2,474
Other investments ^(a)	—			—			(54		)	(54		)
Funding from debt financing, net of fees	—			(9		)	(1,509		)	(1,518		)
Funding from third party equity partners	—			—			(195		)	(195		)
Total capital expenditures and investments, net of financings	$	151		$	29		$	527		$	707

Estimated capital expenditures for the remainder of 2012	$	86		$	11		$	844		$	941
Other investments ^(a)	—			—			58			58
Funding from debt financing, net of fees	(5		)	(34		)	(662		)	(701		)
Funding from third party equity partners	—			—			(77		)	(77		)
NRG estimated capital expenditures for the remainder of 2012, net of financings	$	81		$	(23	)	$	163		$	221


(a)	Other investments includes restricted cash activity and proceeds from cash grants.


•	Maintenance and Environmental capital expenditures — For the nine months ended September 30, 2012, the Company's environmental capital expenditures included $24 million related to a project to install selective catalytic reduction systems, scrubbers and fabric filters on Indian River Unit 4. The system was operational at year-end 2011.


•	Growth Investments capital expenditures — For the nine months ended September 30, 2012, the Company's growth investment expenditures included $2.54 billion for solar projects and $154 million for the Company's El Segundo project. In 2012, NRG will be continuing its efforts on the solar and El Segundo projects.

Environmental Capital Expenditures

Based on current rules, technology and plans, as well as preliminary plans based on proposed rules, NRG has estimated that environmental capital expenditures from 2012 through 2016 to meet NRG's environmental commitments will be approximately $440 million. These costs are primarily associated with mercury controls to satisfy MATS on the Company's Big Cajun II, W.A. Parish and Limestone facilities and a number of intake modification projects across the fleet under state or proposed federal

316(b) rules. The change from our previous estimate of $553 million reflects a decrease in costs related to changes in technology related to MATS compliance, completing projects below budget, and shifts in compliance schedules based on regulatory changes. NRG continues to explore cost effective compliance alternatives to reduce costs. While this estimate reflects anticipated schedules and controls related to the proposed 316(b) Rule, the full impact on the scope and timing of environmental retrofits from any new or revised regulations cannot be determined until these rules are final and any legal challenges are reviewed. However, NRG believes it is positioned to meet more stringent requirements through its planned capital expenditures, existing controls, and increasing generation from renewable resources.

2012 Capital Allocation Program

On February 28, 2012, the Company announced its intention to initiate an annual common stock dividend of $0.36 per share, and paid its first quarterly dividend on the Company's common stock of $0.09 per share on August 15, 2012. On October 15, 2012, NRG declared a quarterly dividend on the Company's common stock of $0.09 per share, payable November 15, 2012, to shareholders of record as of November 1, 2012.

During the second quarter of 2012, the Company paid $72 million for open market repurchases of the Company's Senior Notes due 2021, at an average price of 98.58% of face value.

On September 24, 2012, NRG issued $990 million aggregate principal amount at par of 6.625% Senior Notes due 2023, or the 2023 Senior Notes. The Company used the proceeds, net of issuance costs, of $978 million for the 2023 Senior Notes and additional cash on-hand to redeem $820 million of 2017 Senior Notes through a tender offer, at an early redemption percentage of 104.125%. On October 9, 2012, an additional $0.4 million was tendered at a redemption percentage of 101.125%, and on October 24, 2012, the remaining $270 million of 2017 Senior Notes were redeemed, at a redemption percentage of 103.688%. This refinancing simplifies the Company's capital structure and creates a single covenant package across credit facilities and debt securities, enabling NRG to invest more opportunistically in growth initiatives and enhance its ability to efficiently return capital to all investors.

As part of the 2012 program, the Company plans to invest approximately $238 million in maintenance and environmental capital expenditures in existing assets, and approximately $690 million in solar and other projects under development.

Pending Acquisition

Under the terms of the Merger Agreement entered into on July 20, 2012, in connection with the pending acquisition, should NRG request it, GenOn will commence a “change of control” tender offer for specified GenOn debt, conditioned on the completion of the merger, or the Change in Control Offers. In addition, under the terms of the Merger Agreement, NRG may, at its election following consultation with GenOn, commence a tender offer for cash or an exchange offer for securities for all or any portion of specified GenOn debt, conditioned on the completion of the merger, which together with the Change in Control Offers, are referred to as the Debt Offers. NRG may, under the terms of the Merger Agreement, elect to also undertake a consent solicitation to alter the terms of specified GenOn debt outstanding after such tender or exchange offers. NRG intends to fund the Debt Offers and the related fees, commissions and expenses with a combination of funds available at each company (including funds available under existing credit facilities) and, to the extent necessary, new financing. On July 20, 2012, NRG obtained commitment letters from two financial institutions to fund up to $1.6 billion under a new senior secured term loan facility, to the extent such funds are necessary to consummate the Debt Offers. On October 19, 2012, NRG elected to amend the commitment letters to permanently reduce the aggregate commitment amount to $1.0 billion, and intends to fund additional requirements, if any, from available liquidity including cash on hand and credit facilities. NRG has agreed to use reasonable best efforts to obtain the financing, to the extent required, and GenOn has agreed to use reasonable best efforts to cooperate in NRG's efforts to obtain the financing. There are no financing conditions to the merger and the merger is not conditioned upon the completion of the Debt Offers or the funding of the financing.

Cash Flow Discussion

The following table reflects the changes in cash flows for the comparative nine month periods:



Nine months ended September 30,	2012			2011			Change
	(In millions)
Net cash provided by operating activities	$	1,058		$	668		$	390
Net cash used by investing activities	(2,329		)	(2,161		)	(168		)
Net cash provided/(used) by financing activities	1,779			(333		)	2,112

Net Cash Provided By Operating Activities

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



	(In millions)
Increase in operating income adjusted for non-cash charges	$	212
Change in cash paid in support of risk management activities, including option premium collected/paid, primarily related to margin posted for retail supply positions	313
Other changes in working capital	(135		)
	$	390

Net Cash Used By Investing Activities

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



	(In millions)
Increase in capital expenditures due to increased spending on maintenance and RepoweringNRG, primarily for solar projects under construction	$	(1,119	)
Decrease in restricted cash, which was mainly to support equity requirements for U.S. DOE funded projects	463
Decrease in cash paid for acquisitions, which primarily reflects the acquisition of Energy Plus and three Solar projects in 2011	312
Increase in proceeds from sale of assets, primarily related to the sale of Schkopau in 2012	123
Increase in notes receivable, primarily for reimbursable network upgrades	(49		)
Proceeds from renewable energy grants	49
Net increase in purchases and sales of emissions allowances	19
Proceeds from insurance claims	15
Other	19
	$	(168	)

Net Cash Provided By Financing Activities

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



	(In millions)
Net increase in borrowings, primarily related to financing arrangements for solar projects in construction	$	1,326
Cash paid for repurchases of treasury stock in 2011	378
Proceeds from the sale of noncontrolling interest and other contributions from noncontrolling interests	316
Decrease in payments for debt issuance costs, primarily related to the issuance of the 2018, 2019 and 2021 Senior Notes in 2011	119
Payment of dividends to common stockholders in 2012	(21		)
Other	(6		)
	$	2,112

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

For the nine months ended September 30, 2012 the Company had a total domestic pre-tax book loss of $208 million and foreign pre-tax book income of $23 million. For the nine months ended September 30, 2012, the Company generated domestic net operating losses, or NOLs, of $204 million. As of September 30, 2012, the Company has cumulative domestic NOL carryforwards of $711 million for financial statement purposes. In addition, NRG has cumulative foreign NOL carryforwards of $254 million, of which $73 million will expire starting 2012 through 2019 and of which $181 million do not have an expiration date.

In addition to these amounts, the Company has $198 million of tax effected uncertain tax benefits. 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 $30 million in 2012.

However, as the position remains uncertain for the $198 million of tax effected uncertain tax benefits, the Company has recorded a non-current tax liability of $67 million and may accrue the remaining balance as an increase to non-current liabilities until final resolution with the related taxing authority. The $67 million non-current tax liability for uncertain tax benefits is primarily from positions taken on various state returns, including accrued interest.

The Company continues to be under federal examination for tax years 2007 through 2010 and continues to be under examination for various state and foreign jurisdictions for multiple years.

New and On-going Company Initiatives and Development Projects

NRG has a comprehensive set of initiatives and development projects that supports its strategy focused on: (i) excellence in safety and enhanced operating performance; (ii) earning a margin by selling electricity to end-use customers; (iii) development of new renewable and conventional power generation projects and repowering of power generation assets at existing sites; (iv) empowering retail customers with distinctive products and services; (v) engaging in a proactive capital allocation plan; and (vi) pursuing selective acquisitions, joint ventures, divestitures and investments in new and existing energy-related businesses and new technologies in order to enhance the Company's asset mix.

Renewable Development and Acquisitions

As part of its core strategy, NRG intends to continue to invest in the development and acquisition of renewable energy projects, primarily solar. 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 presence in regions with attractive renewable resources and the prevalence, in the Company's core markets, of state-mandated renewable portfolio standards. A brief description of the Company's development efforts with respect to solar renewable technology follows.

Solar

NRG has acquired and is developing a number of solar projects utilizing photovoltaic, or PV, as well as solar thermal technologies. The following table is a brief summary of the Company's major Utility Scale Solar projects as of September 30, 2012, that are under construction.



NRG Owned Projects	Location	PPA	MW ^(a)	Expected COD	Status
Ivanpah ^(b)	Ivanpah, CA	20 - 25 year	392	2013	Under Construction
Agua Caliente ^(c)	Yuma County, AZ	25 year	290	2012 - 2014	Partially In-Service
CVSR	San Luis Obispo, CA	25 year	250	2012 - 2013	Partially In-Service
Alpine	Lancaster, CA	20 year	66	2012	Under Construction
Borrego	Borrego Springs, CA	25 year	26	2012	Under Construction
Avra Valley	Pima County, AZ	20 year	25	2012	Under Construction


(a)	Represents total project size.


(b)	NRG owns a 50.1% stake in the Ivanpah solar project.


(c)	NRG owns a 51% stake in the 290 MW Agua Caliente project which includes 230 MW that reached commercial operations from January through September of 2012.

Below is a summary of recent developments related to solar projects:

Ivanpah — In 2011, NRG acquired 50.1% of the 392 MW Ivanpah solar project, or Ivanpah, in Ivanpah, CA. The first unit of the Ivanpah project is expected to be completed and producing power in early May of 2013. The second and third units are expected be completed in the third and fourth quarters of 2013. Power generated from Ivanpah will be sold to Southern California Edison and Pacific Gas and Electric, under multiple 20 to 25 year PPAs.

Agua Caliente — In 2011, NRG acquired 100% of the 290 MW Agua Caliente solar project, or Agua Caliente, in Yuma, AZ. On January 18, 2012, the Company completed the sale of a 49% interest in NRG Solar AC Holdings LLC, the indirect owner of Agua Caliente, to MidAmerican. Operations are scheduled to commence in phases through the first quarter of 2014, with 230 MW achieving commercial operations from January through September of 2012. On April 12, 2012, the Company received permission from the U.S. DOE to accelerate the block completion schedule. The impact of this decision has allowed the Company to bring blocks on-line sooner and shortens the commercial operations date of the entire project by three months to March 2014. The acceleration has resulted in greater earnings earlier than originally anticipated, along with acceleration of payments under the Engineering, Procurement and Construction, or EPC, agreement which has been funded with earlier draw downs under the Agua Caliente Financing Agreement, as well as equity support by the partners. Power generated from Agua Caliente is being sold to Pacific Gas and Electric under a 25 year PPA. While full commercial operations of the entire project will be achieved in early 2014, the maximum capacity deliverable under the PPA of 290 MWs will be on line by the third quarter of 2013.

CVSR — NRG owns 100% of the 250 MW CVSR project in eastern San Luis Obispo County, California. During the second quarter, the Company met the conditions necessary to permit loan disbursements under the CVSR Financing Agreement, as discussed in Note 8, Debt and Capital Leases, to this Form 10-Q. Operations commenced on the first 22 MW phase in September, with additional phases beginning in the fourth quarter of 2012 through the fourth quarter of 2013. Power generated from CVSR is sold to Pacific Gas and Electric under a 25 year PPA.

Alpine — Alpine, located in Lancaster, CA, is a 66 MW facility utilizing First Solar thin film solar modules. The project, which is anticipated to reach commercial operations in the fourth quarter of 2012, obtained financing during the first quarter of 2012, as discussed in Note 8, Debt and Capital Leases, to this Form 10-Q. Power generated from Alpine will be sold to Pacific Gas and Electric under a 20 year PPA.

Avra Valley — Avra Valley, located in Pima County, NM, is a 25 MW facility utilizing First Solar thin film solar modules with a single axis tracking system. The project, which is anticipated to reach commercial operations in the fourth quarter of 2012, obtained financing during the third quarter of 2012, as discussed in Note 8, Debt and Capital Leases, of this Form 10-Q. Power generated from Avra Valley will be sold to Tucson Electric Power Company under a 20 year PPA.

Distributed Solar — The MetLife Stadium project was completed during the third quarter. NRG's installation of solar power generating systems at Gillette Stadium and Lincoln Financial Field are continuing, with commercial operations expected by the end of the fourth quarter of 2012. Also anticipated in the fourth quarter is the completion of a portfolio of 16 projects in southern California totaling 9 MWs, of which 51% is owned by NRG. Finally, NRG will complete and place in service six projects for Arizona State University during the fourth quarter. All of the Company's Distributed Solar projects in operation or under construction are supported by long-term PPAs.

Conventional Power Development

Projects Under Construction

The Company's El Segundo Energy Center LLC, or ESEC, is continuing construction at its El Segundo Power Generating Station, a 550 MW fast start, gas turbine combined cycle generating facility in El Segundo, California. The facility is being constructed pursuant to a 10 year, 550 MW PPA with Southern California Edison Company, or SCE. The Company expects a commercial operation date of August 1, 2013.

Retail Growth Initiatives

The Company's Retail businesses continue to expand in both Texas and the Northeast through its innovative partnerships, channels, product lines and value propositions. Through the first nine months of 2012, NRG has grown customer count by 45,000 in Texas and by 79,000 in the Northeast markets. In addition, NRG launched sales to businesses, manufacturing facilities, government entities and institutions in Ohio and New York. NRG's Retail businesses are currently operating in 11 states including Texas, Connecticut, Delaware, Illinois, Maryland, Massachusetts, New Jersey, New York, Oregon, Ohio and Pennsylvania, as well as the District of Columbia.

NRG also continues to expand its innovative solutions, with over 700,000 customers using one of eSense^TM smart energy solutions giving customers energy insights, choices and convenience solutions. Additionally, NRG's Retail businesses continue to expand the Home Solutions^SM business with almost 330,000 customers utilizing home services products including protection products such as surge protection, in home power line protection, HVAC maintenance and energy efficiency products such as air filter delivery and solar panel leasing.

Electric Vehicle Infrastructure Development

NRG, through its subsidiary eVgo, continues its build out and operation of the Houston and Dallas/Fort Worth Metroplex, or DFW, EV ecosystems, and the Company is on track to be the first company to equip an entire major market with the privately funded infrastructure needed for successful EV adoption and integration. As of September 30, 2012, eVgo had 16 public fast charging Freedom Station sites operational in Houston, and 14 in DFW. These two ecosystems are the largest privately-funded comprehensive direct current fast-charging networks in the nation. In addition, eVgo had 5 sites in the newly entered Washington, DC/Baltimore market under construction or in permitting. eVgo offers consumers a subscription-based plan that provides for all charging requirements for EVs at a competitive monthly fee.

Additionally, eVgo has entered into an agreement with the CPUC to build at least 200 public fast charging Freedom Station sites and wiring and associated work to prepare 10,000 commercial and multi-family parking spaces for electric vehicle charging in California. The agreement is part of a legal settlement, as discussed in detail in Note 14, Commitments and Contingencies, of this Form 10-Q, and is pending FERC approval.

W.A. Parish Peaking Unit and Commercial Scale Carbon Capture, Utilization and Storage System

On May 3, 2012 NRG entered into a financing arrangement in the form of a $54 million tax-exempt bond financing, as discussed in Note 8, Debt and Capital Leases, of this Form 10-Q. The proceeds of the bonds will be used in the construction of a peaking unit at the W.A. Parish plant, with one or more components of a commercial scale carbon capture, utilization and storage system, or CCUS, which is sponsored in part by the U.S. DOE. In preparation for construction, NRG, through its wholly owned subsidiary, Petra Nova Power I LLC, or PNP, acquired a gas turbine in late June 2012. On August 14, 2012, PNP entered into an EPC agreement for the construction of the 75 MW peaking unit (prior to its use as a cogeneration facility to provide steam and power to the CCUS) on a turnkey basis and anticipates a commercial operations date during the second quarter of 2013.

Construction of the CCUS is intended to allow NRG, through its wholly owned subsidiary Petra Nova LLC, or Petra Nova, to utilize the captured CO₂ in enhanced oil recovery operations in oil fields on the Texas Gulf Coast. During the third quarter of 2012, the draft Environmental Impact Statement was filed with the U.S. EPA, which issued a Notice of Availability on September 21, 2012, thereby marking the beginning of the 45-day public comment period required under the National Environmental Policy Act.

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.

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, 2012, 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, 2012, 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. Several of these investments are variable interest entities for which NRG is not the primary beneficiary. See also Note 9, Variable Interest Entities, or VIEs, to this Form 10-Q.

NRG's pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $240 million as of September 30, 2012. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG. See also Note 16, Investments Accounted for by the Equity Method and Variable Interest Entities, to the Company's 2011 Form 10-K.

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 2011 Form 10-K. See also Note 8, Debt and Capital Leases, and Note 14, 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, 2012.

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 or retail load obligations. 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 7 — Management's Discussion and Analysis of Financial Condition and Results of Operations, of the Company's 2011 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, 2012, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at September 30, 2012.



Derivative Activity Gains/(Losses)	(In millions)
Fair value of contracts as of December 31, 2011	$	451
Contracts realized or otherwise settled during the period	(362		)
Changes in fair value	(126		)
Fair value of contracts as of September 30, 2012	$	(37	)



	Fair Value of Contracts as of September 30, 2012
Fair value hierarchy gains/(losses)	Maturity Less Than 1 Year		Maturity 1-3 Years			Maturity 4-5 Years			Maturity in Excess 4-5 Years			Total Fair Value
	(In millions)
Level 1	$	118	$	16		$	(2	)	$	—		$	132
Level 2	97		(144		)	(112		)	(12		)	(171		)
Level 3	—		2			—			—			2
Total	$	215	$	(126	)	$	(114	)	$	(12	)	$	(37	)

The Company has elected to disclose derivative assets and liabilities on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. Also, collateral received or paid on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. Consequently, the magnitude of the changes in individual current and non-current derivative assets or liabilities is higher than the underlying credit and market risk of the Company's portfolio. As discussed in Item 3 - Quantitative and Qualitative Disclosures About Market Risk, Commodity Price Risk, to this Form 10-Q, NRG measures the sensitivity of the Company's portfolio to potential changes in market prices using Value at Risk, or VaR, a statistical model which attempts to predict risk of loss based on market price and volatility. NRG's risk management policy places a limit on one-day holding period VaR, which limits the Company's net open position. As the Company's trade-by-trade derivative accounting results in a gross-up of the Company's derivative assets and liabilities, the net derivative assets and liability position is a better indicator of NRG's hedging activity. As of September 30, 2012, NRG's net derivative liability was $37 million, a decrease to total fair value of $488 million as compared to December 31, 2011. This decrease was primarily driven by the roll-off of trades that settled during the period in addition to losses in fair value due to the decreases in coal prices.

Based on a sensitivity analysis using simplified assumptions, the impact of a $.50 per MMBtu increase in natural gas prices across the term of the derivative contracts would result in a decrease of approximately $125 million in the net value of derivatives as of September 30, 2012. The impact of a $0.50 per MMBtu decrease in natural gas prices across the term of derivative contracts would result in an increase of approximately $85 million in net value of derivatives as of September 30, 2012.

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, legal and regulatory challenges, and the fair value of certain assets and liabilities. 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 has 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 information that gives rise to the revision becomes known.

The Company identifies its most critical accounting policies as those that are the most pervasive and important to the portrayal of the Company's financial position and results of operations, and that require the most difficult, subjective and/or complex judgments by management regarding estimates about matters that are inherently uncertain. NRG's critical accounting policies include derivative instruments, income taxes and valuation allowance for deferred tax assets, impairment of long lived assets, goodwill and other intangible assets, and contingencies.

ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

NRG is exposed to several market risks in the Company's normal business activities. Market risk is the potential loss that may result from market changes associated with the Company's merchant power generation or with an existing or forecasted financial or commodity transaction. The types of market risks the Company is exposed to are commodity price risk, interest rate risk, 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 7A — Quantitative and Qualitative Disclosures About Market Risk, of the Company's 2011 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 Monte Carlo simulation based VaR model to estimate 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, 2012, the VaR for NRG's commodity portfolio, including generation assets, load obligations and bilateral physical and financial transactions calculated using the VaR model was $84 million.

The following table summarizes average, maximum and minimum VaR for NRG for the three and nine months ended September 30, 2012, and 2011:



(In millions)	2012		2011
VaR as of September 30	$	84	$	74
Three months ended September 30:
Average	$	79	$	72
Maximum	87		77
Minimum	70		62
Nine months ended September 30:
Average	$	59	$	59
Maximum	87		77
Minimum	24		44

In order to provide additional information for comparative purposes to NRG's peers, the Company also uses VaR to estimate the potential loss of derivative financial instruments that are subject to mark-to-market accounting. These derivative instruments include transactions that were entered into for both asset management and trading purposes. The VaR for the derivative financial instruments calculated using the diversified VaR model as of September 30, 2012, for the entire term of these instruments entered into for both asset management and trading, was $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. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combination of the variable rate debt and the interest rate derivative instrument. NRG's risk management policies allow the Company to reduce interest rate exposure from variable rate debt obligations.

NRG has outstanding interest rate swaps intended to hedge the risks associated with floating interest rates. For the interest rate swaps, the Company will pay its counterparty the equivalent of a fixed interest payment on a predetermined notional value, and NRG receives the monthly equivalent of a floating interest payment based on the 1-month LIBOR calculated on the same notional value. All interest rate swap payments by NRG and its counterparties are made monthly and the LIBOR is determined in advance of each interest period. The total notional amount of the swaps, which mature on February 1, 2013, is $900 million.

In addition to those discussed above, the Company's project subsidiaries enter into interest rate swaps, intended to hedge the risks associated with interest rates on non-recourse project level debt. See Note 12, Debt and Capital Leases, of the Company's 2011 Form 10-K, as well as Note 8, Debt and Capital Leases of this Form 10-Q, for more information on the Company's interest rate swaps.

If all of the above swaps had been discontinued on September 30, 2012, the Company would have owed the counterparties $114 million. Based on the investment grade rating of the counterparties, NRG believes its exposure to credit risk due to nonperformance by counterparties to its hedge contracts to be insignificant.

As part of the CVSR financing, the Company entered into swaptions with a notional value of $586 million in order to hedge the project interest rate risk. If the swaptions were discontinued on September 30, 2012, the counterparty would have owed the Company approximately $5 million.

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, 2012, a 1% change in interest rates would result in a $14 million change in interest expense on a rolling twelve month basis.

As of September 30, 2012, the fair value of the Company's debt was $11.8 billion and the related carrying amount was $11.3 billion. NRG estimates that a 1% decrease in market interest rates would have increased the fair value of the Company's long-term debt by $840 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 $0.50 per MMBtu change in natural gas prices across the term of the marginable contracts would cause a change in margin collateral posted of approximately $84 million as of September 30, 2012, and a 1 MMBtu/MWh change in heat rates for heat rate positions would result in a change in margin collateral posted of approximately $47 million as of September 30, 2012. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of September 30, 2012.

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 arrangements, 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

In connection with the sale of Schkopau, as described in Note 3, Business Acquisitions and Dispositions to this Form 10-Q, NRG entered into a foreign currency swap contract to hedge the impact of exchange rate fluctuations on the sale proceeds of €140 million. As of September 30, 2012, NRG recognized approximately $4 million of gains related to the swap, which was recorded within Other income (loss), net in the statement of operations. The Company received cash consideration, net of selling expenses, of $174 million, which included $4 million related to the swap contract that was recorded as a gain within Other income (loss), net in the third quarter.

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) or 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 2012 that materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1 — LEGAL PROCEEDINGS

For a discussion of material legal proceedings in which NRG was involved through September 30, 2012, see Note 14, Commitments and Contingencies, to 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 the Company's 2011 Form 10-K and Part II, Item 1A, Risk Factors, in the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2012.

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

None.

ITEM 3 — DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4 — MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5 — OTHER INFORMATION

None.

ITEM 6 — EXHIBITS



Exhibits
2.1		Agreement and Plan of Merger, dated as of July 20, 2012, by and among NRG Energy, Inc., Plus Energy Corporation and GenOn Energy, Inc. (incorporated herein by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K filed on July 23, 2012).
4.1		Seventieth Supplemental Indenture, dated September 24, 2012, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York (incorporated herein by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on September 24, 2012).
4.2		Form of 6.625% Senior Note due 2023 (incorporated herein by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on September 24, 2012).
4.3		Seventy-First Supplemental Indenture, dated as of October 9, 2012, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York (incorporated herein by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on October 12, 2012).
4.4		Seventy-Second Supplemental Indenture, dated as of October 9, 2012, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York (incorporated herein by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K filed on October 12, 2012).
4.5		Seventy-Third Supplemental Indenture, dated as of October 9, 2012, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York (incorporated herein by reference to Exhibit 4.3 to the Company's Current Report on Form 8-K filed on October 12, 2012).
4.6		Seventy-Fourth Supplemental Indenture, dated as of October 9, 2012, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York (incorporated herein by reference to Exhibit 4.4 to the Company's Current Report on Form 8-K filed on October 12, 2012).
4.7		Seventy-Fifth Supplemental Indenture, dated as of October 9, 2012, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York (incorporated herein by reference to Exhibit 4.5 to the Company's Current Report on Form 8-K filed on October 12, 2012).
4.8		Seventy-Sixth Supplemental Indenture, dated as of October 9, 2012, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York (incorporated herein by reference to Exhibit 4.6 to the Company's Current Report on Form 8-K filed on October 12, 2012).
10.1		Registration Rights Agreement, dated September 24, 2012, among NRG Energy, Inc., the guarantors named therein and Deutsche Bank Securities Inc., Merrill, Lynch, Pierce, Fenner & Smith Incorporated, Barclays Capital Inc., Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, Goldman, Sachs & Co., J.P. Morgan Securities LLC, Morgan Stanley & Co. Incorporated and RBS Securities Inc., as initial purchasers (incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed on September 24, 2012).
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

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/ KIRKLAND B. ANDREWS
	Kirkland B. Andrews
	Chief Financial Officer (Principal Financial Officer)


	/s/ RONALD B. STARK
	Ronald B. Stark
Date: November 2, 2012	Chief Accounting Officer (Principal Accounting Officer)

EXHIBIT INDEX



Exhibits
2.1		Agreement and Plan of Merger, dated as of July 20, 2012, by and among NRG Energy, Inc., Plus Energy Corporation and GenOn Energy, Inc. (incorporated herein by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K filed on July 23, 2012).
4.1		Seventieth Supplemental Indenture, dated September 24, 2012, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York (incorporated herein by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on September 24, 2012).
4.2		Form of 6.625% Senior Note due 2023 (incorporated herein by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on September 24, 2012).
4.3		Seventy-First Supplemental Indenture, dated as of October 9, 2012, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York (incorporated herein by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on October 12, 2012).
4.4		Seventy-Second Supplemental Indenture, dated as of October 9, 2012, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York (incorporated herein by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K filed on October 12, 2012).
4.5		Seventy-Third Supplemental Indenture, dated as of October 9, 2012, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York (incorporated herein by reference to Exhibit 4.3 to the Company's Current Report on Form 8-K filed on October 12, 2012).
4.6		Seventy-Fourth Supplemental Indenture, dated as of October 9, 2012, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York (incorporated herein by reference to Exhibit 4.4 to the Company's Current Report on Form 8-K filed on October 12, 2012).
4.7		Seventy-Fifth Supplemental Indenture, dated as of October 9, 2012, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York (incorporated herein by reference to Exhibit 4.5 to the Company's Current Report on Form 8-K filed on October 12, 2012).
4.8		Seventy-Sixth Supplemental Indenture, dated as of October 9, 2012, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York (incorporated herein by reference to Exhibit 4.6 to the Company's Current Report on Form 8-K filed on October 12, 2012).
10.1		Registration Rights Agreement, dated September 24, 2012, among NRG Energy, Inc., the guarantors named therein and Deutsche Bank Securities Inc., Merrill, Lynch, Pierce, Fenner & Smith Incorporated, Barclays Capital Inc., Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, Goldman, Sachs & Co., J.P. Morgan Securities LLC, Morgan Stanley & Co. Incorporated and RBS Securities Inc., as initial purchasers (incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed on September 24, 2012).
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