Edgar Filing: NRG ENERGY, INC.

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NRG 2011.6.30 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: June 30, 2011

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. (Check one):

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

Yes o No x

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.

Yes x No o

As of August 1, 2011, there were 241,251,871 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	86
ITEM 4 — CONTROLS AND PROCEDURES	88
PART II — OTHER INFORMATION	89
ITEM 1 — LEGAL PROCEEDINGS	89
ITEM 1A — RISK FACTORS	89
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	89
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES	89
ITEM 4 — (REMOVED AND RESERVED)	89
ITEM 5 — OTHER INFORMATION	89
ITEM 6 — EXHIBITS	90
SIGNATURES	91

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 the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, or Securities Act, and Section 21E of the Exchange Act. The words “believes,” “projects,” “anticipates,” “plans,” “expects,” “intends,” “estimates,” and similar expressions are intended to identify forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause NRG Energy, Inc.'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 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, 2010, including the following:


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


•	Volatile power supply costs and demand for power;

•

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


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


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


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


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


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


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


•	Price mitigation strategies and other market structures employed by ISOs or RTOs that result in a failure to adequately compensate NRG's generation units for all of its costs;


•	NRG's ability to borrow additional funds and access capital markets, as well as NRG's substantial indebtedness and the possibility that NRG may incur additional indebtedness going forward;


•	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 Senior Credit Facility, and in debt and other agreements of certain of NRG subsidiaries and project affiliates generally;


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


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


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


•	NRG's ability to 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; and


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

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:



2010 Form 10-K		NRG’s Annual Report on Form 10-K for the year ended December 31, 2010

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

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

ASR Agreement		Accelerated Share Repurchase Agreement

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

CAA		Clean Air Act

CAIR		Clean Air Interstate Rule

CAISO		California Independent System Operator

CATR		Clean Air Transport Rule

Capital Allocation Plan		Share repurchase program

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

C&I		Commercial, industrial and governmental/institutional

CFTC		U.S. Commodity Futures Trading Commission

CPS		CPS Energy

CSAPR		Cross-State Air Pollution Rule

DNREC		Delaware Department of Natural Resources and Environmental Control

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

Exchange Act		The Securities Exchange Act of 1934, as amended

FERC		Federal Energy Regulatory Commission

FFB		Federal Financing Bank

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

GHG		Greenhouse Gases

Green Mountain Energy		Green Mountain Energy Company

GWh		Gigawatt hour

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

ISO-NE		ISO New England Inc.



LFRM		Locational Forward Reserve Market

LIBOR		London Inter-Bank Offer Rate

LTIP		Long-Term Incentive Plan

MACT		Maximum Achievable Control Technology

Mass		Residential and small business

MMBtu		Million British Thermal Units

MW		Megawatts

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

NAAQS		National Ambient Air Quality Standards

NINA		Nuclear Innovation North America LLC

NO_x		Nitrogen oxide

NPNS		Normal Purchase Normal Sale

NRC		U.S. Nuclear Regulatory Commission

NYISO		New York Independent System Operator

OCI		Other comprehensive income

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

RepoweringNRG		NRG’s program designed to develop, finance, construct and operate new, highly efficient, environmentally responsible capacity

Revolving Credit Facility		NRG’s $925 million senior secured revolving credit facility, which matures on August 31, 2015, and is a component of NRG’s Senior Credit Facility

SEC		United States Securities and Exchange Commission

Securities Act		The Securities Act of 1933, as amended

Senior Credit Facility		NRG’s senior secured facility, which is comprised of a Term Loan Facility, a $925 million Revolving Credit Facility and a $1.3 billion Funded Letter of Credit Facility

Senior Notes		The Company’s $6.1 billion outstanding unsecured senior notes consisting of $1.1 billion 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 and $1.2 billion of 7.875% senior notes due 2021



SO₂		Sulfur dioxide

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

STPNOC		South Texas Project Nuclear Operating Company

TANE		Toshiba America Nuclear Energy Corporation

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

TEPCO		The Tokyo Electric Power Company of Japan, Inc.

Term Loan Facility		A senior first priority secured term loan, of which approximately $608 million matures on February 1, 2013, and $990 million matures on August 31, 2015, and is a component of NRG’s Senior Credit Facility

U.S.		United States of America

U.S. DOE		United States Department of Energy

U.S. EPA		United States Environmental Protection Agency

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

VaR		Value at Risk

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 June 30,						Six months ended June 30,
(In millions, except for per share amounts)	2011			2010			2011			2010
Operating Revenues
Total operating revenues	$	2,278		$	2,133		$	4,273		$	4,348
Operating Costs and Expenses
Cost of operations	1,608			1,329			2,932			2,968
Depreciation and amortization	222			208			427			410
Selling, general and administrative	167			139			310			269
Development costs	12			13			21			22
Total operating costs and expenses	2,009			1,689			3,690			3,669
Gain on sale of assets	—			—			—			23
Operating Income	269			444			583			702
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates	12			11			10			25
Impairment charge on investment	(11		)	—			(492		)	—
Other income, net	3			19			8			23
Loss on debt extinguishment	(115		)	—			(143		)	—
Interest expense	(167		)	(147		)	(340		)	(300		)
Total other expense	(278		)	(117		)	(957		)	(252		)
(Loss)/Income Before Income Taxes	(9		)	327			(374		)	450
Income tax (benefit)/expense	(630		)	117			(735		)	182
Net Income	621			210			361			268
Less: Net loss attributable to noncontrolling interest	—			(1		)	—			(1		)
Net Income Attributable to NRG Energy, Inc.	621			211			361			269
Dividends for preferred shares	3			3			5			5
Income Available for Common Stockholders	$	618		$	208		$	356		$	264
Earnings Per Share Attributable to NRG Energy, Inc. Common Stockholders
Weighted average number of common shares outstanding — basic	243			255			245			254
Net income per weighted average common share — basic	$	2.54		$	0.82		$	1.45		$	1.04
Weighted average number of common shares outstanding — diluted	244			256			247			256
Net income per weighted average common share — diluted	$	2.53		$	0.81		$	1.44		$	1.03

See notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS



	June 30, 2011			December 31, 2010
(In millions, except shares)	(unaudited)
ASSETS
Current Assets
Cash and cash equivalents	$	1,939		$	2,951
Funds deposited by counterparties	260			408
Restricted cash	145			8
Accounts receivable — trade, less allowance for doubtful accounts of $18 and $25	1,008			734
Inventory	386			453
Derivative instruments valuation	1,749			1,964
Cash collateral paid in support of energy risk management activities	254			323
Prepayments and other current assets	298			296
Total current assets	6,039			7,137
Property, plant and equipment, net of accumulated depreciation of $4,170 and $3,796	12,283			12,517
Other Assets
Equity investments in affiliates	549			536
Note receivable — affiliate and capital leases, less current portion	419			384
Goodwill	1,863			1,868
Intangible assets, net of accumulated amortization of $1,255 and $1,064	1,589			1,776
Nuclear decommissioning trust fund	433			412
Derivative instruments valuation	586			758
Restricted cash supporting Funded Letter of Credit Facility	1,301			1,300
Other non-current assets	274			208
Total other assets	7,014			7,242
Total Assets	$	25,336		$	26,896
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	90		$	463
Accounts payable	842			783
Derivative instruments valuation	1,319			1,685
Deferred income taxes	101			108
Cash collateral received in support of energy risk management activities	260			408
Accrued expenses and other current liabilities	493			773
Total current liabilities	3,105			4,220
Other Liabilities
Long-term debt and capital leases	8,910			8,748
Funded letter of credit	1,300			1,300
Nuclear decommissioning reserve	326			317
Nuclear decommissioning trust liability	278			272
Deferred income taxes	1,709			1,989
Derivative instruments valuation	333			365
Out-of-market contracts	201			223
Other non-current liabilities	598			1,142
Total non-current liabilities	13,655			14,356
Total Liabilities	16,760			18,576
3.625% convertible perpetual preferred stock (at liquidation value, net of issuance costs)	248			248
Commitments and Contingencies
Stockholders’ Equity
Common stock	3			3
Additional paid-in capital	5,339			5,323
Retained earnings	4,156			3,800
Less treasury stock, at cost — 62,972,529 and 56,808,672 shares, respectively	(1,633		)	(1,503		)
Accumulated other comprehensive income	305			432
Noncontrolling interest	158			17
Total Stockholders’ Equity	8,328			8,072
Total Liabilities and Stockholders’ Equity	$	25,336		$	26,896

See notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



(In millions)
Six months ended June 30,	2011			2010
Cash Flows from Operating Activities
Net income	$	361		$	268
Adjustments to reconcile net income to net cash provided by operating activities:
Distributions and equity in earnings of unconsolidated affiliates	—			(9		)
Depreciation and amortization	427			410
Provision for bad debts	20			22
Amortization of nuclear fuel	20			19
Amortization of financing costs and debt discount/premiums	16			15
Loss on debt extinguishment	26			—
Amortization of intangibles and out-of-market contracts	92			1
Changes in deferred income taxes and liability for uncertain tax benefits	(748		)	179
Changes in nuclear decommissioning trust liability	13			9
Changes in derivatives	(166		)	(55		)
Changes in collateral deposits supporting energy risk management activities	69			(30		)
Impairment charge on investment	481			—
Cash used by changes in other working capital	(302		)	(224		)
Net Cash Provided by Operating Activities	309			605
Cash Flows from Investing Activities
Acquisitions of businesses, net of cash acquired	(68		)	(141		)
Capital expenditures	(839		)	(330		)
Increase in restricted cash, net	(42		)	(11		)
Increase in restricted cash to support equity requirements for U.S. DOE funded projects	(70		)	—
Decrease in notes receivable	20			15
Purchases of emission allowances	(17		)	(45		)
Proceeds from sale of emission allowances	4			11
Investments in nuclear decommissioning trust fund securities	(165		)	(76		)
Proceeds from sales of nuclear decommissioning trust fund securities	152			67
Proceeds from renewable energy grants	—			102
Proceeds from sale of assets	13			30
Investments in unconsolidated affiliates	(15		)	—
Other	(32		)	(7		)
Net Cash Used by Investing Activities	(1,059		)	(385		)
Cash Flows from Financing Activities
Payment of dividends to preferred stockholders	(5		)	(5		)
Payment for treasury stock	(130		)	(50		)
Net (payments for)/receipts from settlement of acquired derivatives that include financing elements	(46		)	27
Installment proceeds from sale of noncontrolling interest in subsidiary	—			50
Proceeds from issuance of long-term debt	3,798			141
Proceeds from issuance of term loan for Funded Letter of Credit Facility	—			1,300
Increase in restricted cash supporting funded letter of credit	(1		)	(1,300		)
Proceeds from issuance of common stock	1			2
Payment of debt issuance costs	(52		)	(53		)
Payments for short and long-term debt	(3,833		)	(459		)
Net Cash Used by Financing Activities	(268		)	(347		)
Effect of exchange rate changes on cash and cash equivalents	6			(9		)
Net Decrease in Cash and Cash Equivalents	(1,012		)	(136		)
Cash and Cash Equivalents at Beginning of Period	2,951			2,304
Cash and Cash Equivalents at End of Period	$	1,939		$	2,168

See notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 — Basis of Presentation

NRG Energy, Inc., or NRG or the Company, is an integrated wholesale power generation and retail electricity company with a significant presence in major competitive power markets in the United States. NRG is engaged in: the ownership, development, construction and operation of power generation facilities; the transacting in and trading of fuel and transportation services; the trading of energy, capacity and related products in the United States and select international markets; and the supply of electricity, energy services, and cleaner energy products to retail electricity customers in deregulated markets through its retail subsidiaries Reliant Energy and Green Mountain Energy Company, or Green Mountain Energy.

The accompanying unaudited interim condensed consolidated financial statements have been prepared in accordance with the SEC's regulations for interim financial information and with the instructions to Form 10-Q. Accordingly, they do not include all of the information and notes required by generally accepted accounting principles for complete financial statements. The following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to the Company's financial statements in its Annual Report on Form 10-K for the year ended December 31, 2010, or 2010 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 June 30, 2011, the results of operations for the three and six months ended June 30, 2011, and 2010, and cash flows for the six months ended June 30, 2011, and 2010.

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 — Other Cash Flow Information

NRG’s investing activities exclude capital expenditures of $204 million which were accrued and unpaid at June 30, 2011.

Note 3 — Comprehensive Income

The following table summarizes the components of the Company's comprehensive income, net of tax:



	Three months ended June 30,						Six months ended June 30,
(In millions)	2011			2010			2011			2010
Net Income attributable to NRG Energy, Inc.	$	621		$	211		$	361		$	269
Changes in derivative activity	(67		)	(154		)	(149		)	103
Foreign currency translation adjustment	10			(36		)	22			(42		)
Unrealized loss on available-for-sale securities	(1		)	(1		)	—			(1		)
Other comprehensive (loss)/income	(58		)	(191		)	(127		)	60
Comprehensive income attributable to NRG Energy, Inc.	$	563		$	20		$	234		$	329

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



(In millions)
Accumulated other comprehensive income as of December 31, 2010	$	432
Changes in derivative activity	(149		)
Foreign currency translation adjustment	22
Accumulated other comprehensive income as of June 30, 2011	$	305

Note 4 — Business Acquisitions and Disposition

2011 Acquisitions

Ivanpah — On April 5, 2011, NRG acquired a 50.1% stake in the 392 MW Ivanpah Solar Electric Generation System, or Ivanpah, from BrightSource Energy, Inc., or BSE, for cash consideration of $68 million. In addition, NRG committed to contribute up to an additional $232 million into Ivanpah, against which it paid $7 million for debt issuance costs and posted $192 million of collateral, which included $70 million in cash and $122 million in a letter of credit. The Company may increase its letter of credit to replace the cash collateral at its discretion. The Company has recorded the $70 million of cash collateral as restricted cash on the consolidated balance sheet as of June 30, 2011. In addition to the cash collateral of $70 million, Ivanpah had approximately $52 million of restricted cash as of June 30, 2011, which primarily represented cash collateral for its various agreements.

Ivanpah is composed of three separate facilities - Ivanpah 1 (126 MW), Ivanpah 2 (133 MW) and Ivanpah 3 (133 MW), all of which are expected to be fully operational by the end of 2013. Ivanpah has received project financing of $1.6 billion from the Federal Financing Bank, or FFB, under a credit agreement, or the Ivanpah Credit Agreement, which is guaranteed by the United States Department of Energy, or U.S. DOE. As of June 30, 2011, approximately $474 million of borrowings were outstanding under the Ivanpah Credit Agreement. The terms of the borrowings are described further in Note 9, Long-Term Debt. Power generated from Ivanpah will be sold to Southern California Edison and Pacific Gas and Electric, under multiple 20 to 25 year Power Purchase Agreements, or PPAs.

The acquisition is accounted for under the acquisition method of accounting in accordance with Accounting Standards Codification, or ASC, 805, Business Combinations, with identifiable assets acquired and liabilities assumed provisionally recorded at their estimated fair values on the acquisition date. The purchase price was primarily allocated to property, plant and equipment of $492 million, restricted cash of $25 million, other current assets of $29 million, other non-current assets of $7 million, accrued expenses of $327 million, $4 million of debt and accrued interest and a non-controlling interest of $154 million. The non-controlling interest represents the fair value of the capital contributions from the minority investors in Ivanpah. The provisional amounts recognized are subject to revision until evaluations are completed and to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date. The provisional fair value of the property, plant and equipment at the acquisition date was measured primarily based on significant inputs that are not observable in the market and thus represent a Level 3 measurement as defined in ASC 820, Fair Value Measurement. The fair value of the property, plant and equipment was valued using a cost approach, which estimates value by determining the current cost of replacing the asset with another equivalent economic utility.

2010 Acquisitions

The Company made several acquisitions in 2010, which were recorded as business combinations under ASC 805. Those acquisitions for which purchase accounting was not finalized as of December 31, 2010 are briefly summarized below. See Note 3, Business Acquisitions and Note 12, Debt and Capital Leases, in the Company's 2010 Form 10-K for additional information related to these acquisitions.

Green Mountain Energy — On November 5, 2010, NRG acquired Green Mountain Energy for $357 million in cash, net of $75 million cash acquired, funded from cash on hand. The identifiable assets acquired and liabilities assumed were provisionally recorded at their estimated fair values on the acquisition date, and 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. Any changes to the fair value assessments will affect the acquisition-date fair value of goodwill.

Cottonwood — On November 15, 2010, NRG acquired the Cottonwood Generating Station, or Cottonwood, a 1,265 MW combined cycle natural gas plant in the Entergy zone of east Texas for $507 million in cash, funded from cash on hand. The purchase price was primarily allocated to fixed assets acquired, which were recorded at provisional fair value on the acquisition date. The accounting for Cottonwood was considered complete as of March 31, 2011, at which point the provisional fair values became final.

2010 Disposition

Padoma — On January 11, 2010, NRG sold its terrestrial wind development company, Padoma Wind Power LLC, or Padoma, to Enel North America, Inc. NRG recognized a gain on the sale of Padoma of $23 million, which was recorded as a component of operating income in the statement of operations during the six months ended June 30, 2010.

Note 5 — Nuclear Innovation North America LLC Developments, Including Impairment Charge

Nuclear Innovation North America LLC, or NINA, which is majority-owned by NRG, was established in May 2008 to focus on marketing, siting, developing, financing and investing in new advanced design nuclear projects in select markets across North America, including the planned South Texas Project Units 3 and 4, or STP 3 & 4, Project. Toshiba America Nuclear Energy Corporation, or TANE, a wholly-owned subsidiary of Toshiba Corporation, is the minority owner of NINA. NINA is a bankruptcy remote entity under NRG's corporate structure and designated as an Excluded Project Subsidiary under NRG's Senior Credit Facility and senior unsecured notes, which require that NRG not be obligated to contribute any capital to service NINA's debt or fund the repayment of any NINA debt in the event of a default. Furthermore, NRG is not required to continue the funding of NINA and any capital provided to NINA by any other equity partner could result in the dilution of NRG's equity interest.

On March 11, 2011, Japan was hit by a devastating earthquake and tsunami which, in turn, triggered a nuclear incident at the Fukushima Daiichi Nuclear Power Station owned by The Tokyo Electric Power Company of Japan, Inc., or TEPCO. The nuclear incident in Japan introduced multiple and substantial uncertainties around new nuclear development in the United States and the availability of debt and equity financing to NINA. Consequently, NINA announced, on March 21, 2011, that it was reducing the scope of development at the STP 3 & 4 expansion to allow time for the U.S. Nuclear Regulatory Commission, or NRC, and other nuclear stakeholders to assess the impacts from the events in Japan. NINA suspended indefinitely all detailed engineering work and other pre-construction activities and, as a result, dramatically reduced the project workforce. The decision to reduce the scope of activities was made jointly by NINA, NRG and Toshiba. Further, on April 19, 2011, NRG announced that, while it will cooperate with and support its current partners and any prospective future partners in attempting to develop STP 3 & 4 successfully, NRG was withdrawing from further financial participation in NINA's development of STP 3 & 4. NINA, going forward, will be focused solely on securing a combined operating license from the NRC and on obtaining the loan guarantee from the U.S. DOE, two items that are essential to the success of any future project development. TANE agreed, for the time being, to assume responsibility for NINA's ongoing costs associated with continuation of the licensing process. In concurrence with the substantial reduction in NINA's project workforce, and to support NINA's reduced scope of work, NRG has contributed approximately $11 million to NINA in the second quarter of 2011, and expects to incur additional one-time costs, related to contributions to NINA, of up to $9 million, bringing these total expected costs to $20 million. These contributions are expensed as incurred to "Impairment charge on investment."

Due to the events described above, NRG evaluated its investment in NINA for impairment. As part of this process, NRG evaluated the contractual rights and economic interests held by the various stakeholders in NINA, and concluded that while it continues to hold majority legal ownership, NRG ceased to have a controlling financial interest in NINA at the end of the first quarter of 2011. Consequently, NRG deconsolidated NINA as of March 31, 2011, in accordance with ASC-810, Consolidation, or ASC 810. This resulted in the removal of the following amounts from NRG's consolidated balance sheet: $930 million of construction in progress; $154 million of accounts payable and accrued expenses; $297 million of long-term debt; $17 million of non-controlling interest; and $19 million of other assets and liabilities. Furthermore, NRG assessed the impact of the diminished prospects for the STP 3 & 4 project on the fair value of NINA's assets relative to NINA's existing liabilities as well as NINA's potential contingent liabilities. Based on this assessment, the Company concluded it was remote that NRG would recover any portion of the carrying amount of its equity investment in NINA and, consequently, recorded an impairment charge of $492 million for the six months ended Six months ended June 30, 2011, for the full amount of its investment, including $481 million as of March 31, 2011, and $11 million from the 2011 second quarter. This impairment charge included net assets contributed from all of NINA's equity investors, both NRG and TANE, which the Company previously consolidated.

As part of a March 1, 2010, settlement of litigation with CPS Energy, or CPS, NRG had agreed to pay $80 million to CPS, subject to the U.S. DOE's approval of a fully executed term sheet for a conditional U.S. DOE loan guarantee for STP 3 & 4. NRG also had agreed to donate an additional $10 million, unconditionally, over four years in annual payments of $2.5 million to the Residential Energy Assistance Partnership, or REAP, in San Antonio. Payments of $5 million were made to REAP through March 31, 2011. As a result of the events stemming from the nuclear incident in Japan, the Company no longer believes it probable that the conditional U.S. DOE loan guarantee will be received or accepted. Therefore, as of March 31, 2011, the Company reversed the $80 million contingent liability to CPS previously recorded within other current liabilities, along with the $80 million of associated amounts capitalized to construction in progress within property, plant and equipment. At June 30, 2011, $5 million in liabilities remains on the condensed consolidated balance sheet for the obligations to REAP.

Note 6 — Fair Value of Financial Instruments

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



	Carrying Amount				Fair Value
	June 30, 2011		December 31, 2010		June 30, 2011		December 31, 2010
	(In millions)
Assets:
Cash and cash equivalents	$	1,939	$	2,951	$	1,939	$	2,951
Funds deposited by counterparties	260		408		260		408
Restricted cash	145		8		145		8
Cash collateral paid in support of energy risk management activities	254		323		254		323
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities	9		8		9		8
Marketable equity securities	2		3		2		3
Trust fund investments	435		414		435		414
Notes receivable	203		177		214		190
Derivative assets	2,335		2,722		2,335		2,722
Restricted cash supporting funded Letter of Credit Facility	1,301		1,300		1,301		1,300
Liabilities:
Long-term debt, including current portion	8,886		9,104		8,950		9,236
Funded letter of credit	1,300		1,300		1,300		1,295
Cash collateral received in support of energy risk management activities	260		408		260		408
Derivative liabilities	$	1,652	$	2,050	$	1,652	$	2,050

Recurring Fair Value Measurements

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



(In millions)	Fair Value
As of June 30, 2011	Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	1,939	$	—	$	—	$	1,939
Funds deposited by counterparties	260		—		—		260
Restricted cash	145		—		—		145
Cash collateral paid in support of energy risk management activities	254		—		—		254
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities	—		—		9		9
Marketable equity securities	2		—		—		2
Trust fund investments:
Cash and cash equivalents	2		—		—		2
U.S. government and federal agency obligations	37		—		—		37
Federal agency mortgage-backed securities	—		60		—		60
Commercial mortgage-backed securities	—		11		—		11
Corporate debt securities	—		53		—		53
Marketable equity securities	226		—		41		267
Foreign government fixed income securities	—		5		—		5
Derivative assets:
Commodity contracts	700		1,548		87		2,335
Restricted cash supporting Funded Letter of Credit Facility	1,301		—		—		1,301
Total assets	$	4,866	$	1,677	$	137	$	6,680
Cash collateral received in support of energy risk management activities	$	260	$	—	$	—	$	260
Derivative liabilities:
Commodity contracts	707		758		113		1,578
Interest rate contracts	—		74		—		74
Total liabilities	$	967	$	832	$	113	$	1,912



(In millions)	Fair Value
As of December 31, 2010	Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	2,951	$	—	$	—	$	2,951
Funds deposited by counterparties	408		—		—		408
Restricted cash	8		—		—		8
Cash collateral paid in support of energy risk management activities	323		—		—		323
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities	—		—		8		8
Marketable equity securities	3		—		—		3
Trust fund investments:
Cash and cash equivalents	9		—		—		9
U.S. government and federal agency obligations	27		—		—		27
Federal agency mortgage-backed securities	—		57		—		57
Commercial mortgage-backed securities	—		11		—		11
Corporate debt securities	—		56		—		56
Marketable equity securities	213		—		39		252
Foreign government fixed income securities	—		2		—		2
Derivative assets:
Commodity contracts	652		2,046		24		2,722
Restricted cash supporting Funded Letter of Credit Facility	1,300		—		—		1,300
Total assets	$	5,894	$	2,172	$	71	$	8,137
Cash collateral received in support of energy risk management activities	$	408	$	—	$	—	$	408
Derivative liabilities:
Commodity contracts	660		1,251		51		1,962
Interest rate contracts	—		88		—		88
Total liabilities	$	1,068	$	1,339	$	51	$	2,458

There were no transfers during the three months and six months ended June 30, 2011, and 2010, between Levels 1 and 2. The following tables reconcile, for the three months and six months ended June 30, 2011, and 2010, 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 June 30, 2011										Six months ended June 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	$	40	$	(11	)	$	38		$	8	$	39	$	(27	)	$	20
Total gains and losses (realized/unrealized):
Included in earnings	—		—		10			10			—		—		19			19
Included in OCI	—		—		—			—			1		—		—			1
Included in nuclear decommissioning obligations	—		—		—			—			—		1		—			1
Purchases	—		1		5			6			—		1		8			9
Transfers into Level 3 ^(b)	—		—		(12		)	(12		)	—		—		(30		)	(30		)
Transfers out of Level 3^(b)	—		—		(18		)	(18		)	—		—		4			4
Ending balance as of June 30, 2011	$	9	$	41	$	(26	)	$	24		$	9	$	41	$	(26	)	$	24
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 June 30, 2011	$	—	$	—	$	5		$	5		$	—	$	—	$	7		$	7



	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Three months ended June 30, 2010											Six months ended June 30, 2010
	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	$	37		$	(25	)	$	21		$	9	$	37		$	(13	)	$	33
Total gains and losses (realized/unrealized):
Included in earnings	—		—			(63		)	(63		)	—		—			(31		)	(31		)
Included in OCI	1		—			—			1			1		—			—			1
Included in nuclear decommissioning obligations	—		(5		)	—			(5		)	—		(5		)	—			(5		)
Purchases	—		—			8			8			—		—			9			9
Transfers into Level 3 ^(b)	—		—			15			15			—		—			(47		)	(47		)
Transfers out of Level 3^(b)	—		—			(11		)	(11		)	—		—			6			6
Ending balance as of June 30, 2010	$	10	$	32		$	(76	)	$	(34	)	$	10	$	32		$	(76	)	$	(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 June 30, 2010	$	—	$	—		$	(61	)	$	(61	)	$	—	$	—		$	(36	)	$	(36	)


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


(b)	Transfers into/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 into/out are with Level 2.

Realized and unrealized gains and losses included in earnings that are related to the energy derivatives are recorded in operating revenues and cost of operations.

In determining the fair value of NRG's Level 2 and 3 derivative contracts, NRG applies a credit reserve to reflect credit risk which is calculated based on credit default swaps. As of June 30, 2011, the credit reserve resulted in a $2 million decrease in fair value which is composed of a $2 million loss in operating revenue and cost of operations. As of June 30, 2010, the credit reserve resulted in an $11 million decrease in fair value which is composed of a $6 million loss in OCI and a $5 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 2010 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 June 30, 2011, counterparty credit exposure to a significant portion of the Company's counterparties was $1.3 billion and NRG held collateral (cash and letters of credit) against those positions of $250 million, resulting in a net exposure of $1.1 billion. Counterparty credit exposure is discounted at the risk free rate. The following tables highlight the counterparty credit quality and the net counterparty credit exposure by industry sector. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market and Normal Purchase Normal Sale, or NPNS, and non-derivative transactions. The exposure is shown net of collateral held, and includes amounts net of receivables or payables.



	Net Exposure ^(a)
Category	(% of Total)
Financial institutions	53	%
Utilities, energy merchants, marketers and other	38
Coal and emissions	4
ISOs	5
Total as of June 30, 2011	100	%



	Net Exposure ^(a)
Category	(% of Total)
Investment grade	73	%
Non-Investment grade	3
Non-rated ^(b)	24
Total as of June 30, 2011	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 was $251 million. Approximately 77% of NRG's positions relating to this credit risk roll-off by the end of 2012. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration. Given the credit quality, diversification and term of the exposure in the portfolio, NRG does not anticipate a material impact on the Company's financial 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 a coal supply agreement. 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 June 30, 2011, credit risk exposure to these counterparties is approximately $700 million for the next five years. This amount excludes potential credit exposure 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. In the case of the coal supply agreement, NRG holds a lien against the underlying asset. These factors significantly reduce the risk of loss.

Retail Customer Credit Risk

NRG is exposed to credit risk through the Company's competitive electricity supply business, which serves retail customers. 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 June 30, 2011, the Company's retail customer credit exposure to C&I customers was diversified across many customers and various industries, with a significant portion of the exposure residing at government entities.

NRG is also exposed to retail customer credit risk relating to its Mass customers, which may result in a write-off of bad debt. During 2011, the Company continued to experience improved customer payment behavior, but current economic conditions may affect the ability of the Company's customers to pay bills in a timely manner, which could increase customer delinquencies and may lead to an increase in bad debt expense.

This footnote should be read in conjunction with the complete description under Note 5, Fair Value of Financial Instruments, to the Company's 2010 Form 10-K.

Note 7 — 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 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. 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 to the ratepayers and are not included in net income or accumulated other comprehensive income, consistent with regulatory treatment.

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



	As of June 30, 2011							As of December 31, 2010
(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	$	2	$	—	$	—	—	$	9	$	—	$	—	—
U.S. government and federal agency obligations	35		1		—		10	25		1		—		9
Federal agency mortgage-backed securities	60		3		—		23	57		2		—		24
Commercial mortgage-backed securities	11		—		—		29	11		—		—		29
Corporate debt securities	53		2		1		11	56		3		1		10
Marketable equity securities	267		130		1		—	252		117		1		—
Foreign government fixed income securities	5		—		—		6	2		—		—		8
Total	$	433	$	136	$	2		$	412	$	123	$	2

The following tables summarize 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.



	Six months ended June 30,
(In millions)	2011		2010
Realized gains	$	3	$	2
Realized losses	3		2
Proceeds from sale of securities	152		67

Note 8 — 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 2010 Form 10-K.

Energy-Related Commodities

As of June 30, 2011, NRG had energy-related derivative financial instruments extending through December 2013, 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 June 30, 2011, NRG had interest rate derivative instruments on recourse debt extending through 2013 and on non-recourse debt extending through 2029, 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 June 30, 2011 and December 31, 2010. 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
		June 30, 2011			December 31, 2010
Commodity	Units	(In millions)
Emissions	Short Ton	(2		)	—
Coal	Short Ton	35			34
Natural Gas	MMBtu	(64		)	(175		)
Oil	Barrel	—			1
Power	MWh	10			5
Capacity	MW/Day	—			(1		)
Interest	Dollars	$	1,266		$	2,782

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
(In millions)	June 30, 2011		December 31, 2010		June 30, 2011		December 31, 2010
Derivatives Designated as Cash Flow or Fair Value Hedges:
Interest rate contracts current	$	—	$	—	$	—	$	17
Interest rate contracts long-term	—		—		74		71
Commodity contracts current	329		392		2		2
Commodity contracts long-term	116		217		—		—
Total Derivatives Designated as Cash Flow or Fair Value Hedges	445		609		76		90
Derivatives Not Designated as Cash Flow or Fair Value Hedges:
Commodity contracts current	1,420		1,572		1,317		1,666
Commodity contracts long-term	470		541		259		294
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges	1,890		2,113		1,576		1,960
Total Derivatives	$	2,335	$	2,722	$	1,652	$	2,050

Accumulated Other Comprehensive Income

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



	Three months ended June 30, 2011									Six months ended June 30, 2011
(In millions)	Energy Commodities			Interest Rate			Total			Energy Commodities			Interest Rate			Total
Accumulated OCI beginning balance	$	392		$	(33	)	$	359		$	488		$	(47	)	$	441
Reclassified from accumulated OCI to income:
- Due to realization of previously deferred amounts	(92		)	—			(92		)	(190		)	11			(179		)
Mark-to-market of cash flow hedge accounting contracts	32			(7		)	25			34			(4		)	30
Accumulated OCI ending balance, net of $181 tax	$	332		$	(40	)	$	292		$	332		$	(40	)	$	292
Gains/(losses) expected to be realized from OCI during the next 12 months, net of $134 tax	$	230		$	(2	)	$	228		$	230		$	(2	)	$	228
Gains/(losses) recognized in income from the ineffective portion of cash flow hedges	$	(4	)	$	4		$	—		$	(1	)	$	3		$	2



	Three months ended June 30, 2010									Six months ended June 30, 2010
(In millions)	Energy Commodities			Interest Rate			Total			Energy Commodities			Interest Rate			Total
Accumulated OCI beginning balance	$	719		$	(56	)	$	663		$	461		$	(55	)	$	406
Reclassified from accumulated OCI to income:
- Due to realization of previously deferred amounts	(128		)	(2		)	(130		)	(234		)	—			(234		)
Mark-to-market of cash flow hedge accounting contracts	(16		)	(8		)	(24		)	348			(11		)	337
Accumulated OCI balance ending balance, net of $308 tax	$	575		$	(66	)	$	509		$	575		$	(66	)	$	509
Gains/(losses) expected to be realized from OCI during the next 12 months, net of $186 tax	$	348		$	(32	)	$	316		$	348		$	(32	)	$	316
(Losses)/gains recognized in income from the ineffective portion of cash flow hedges	$	(12	)	$	2		$	(10	)	$	(14	)	$	2		$	(12	)

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

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



	Three months ended June 30,				Six months ended June 30,
(In millions)	2011		2010		2011		2010
Derivative	$	—	$	—	$	—	$	3
Senior Notes (hedged item)	—		—		—		(3		)

Impact of Derivative Instruments on the Statement of Operations

In accordance with ASC 815, unrealized gains and losses associated with changes in the fair value of derivative instruments not accounted for as cash flow hedge derivatives and ineffectiveness of hedge derivatives are reflected in current period earnings.

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



	Three months ended June 30,						Six months ended June 30,
(In millions)	2011			2010			2011			2010
Unrealized mark-to-market results
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	24		$	(51	)	22			$	(91	)
Reversal of loss positions acquired as part of the Reliant Energy acquisition as of May 1, 2009	19			60			47			150
Reversal of loss positions acquired as part of the Green Mountain Energy acquisition as of November 5, 2010	11			—			24			—
Net unrealized (losses)/gains on open positions related to economic hedges	(7		)	48			84			(70		)
Loss on ineffectiveness associated with open positions treated as cash flow hedges	(4		)	(12		)	(1		)	(14		)
Total unrealized mark-to-market gains/(losses) for economic hedging activities	43			45			176			(25		)
Reversal of previously recognized unrealized losses on settled positions related to trading activity	—			8			14			26
Net unrealized gains on open positions related to trading activity	22			9			22			23
Total unrealized mark-to-market for trading activity	22			17			36			49
Total unrealized gains	$	65		$	62		$	212		$	24



	Three months ended June 30,						Six months ended June 30,
(In millions)	2011			2010			2011		2010
Revenue from operations — energy commodities	$	91		$	(83	)	$	104	$	(14	)
Cost of operations	(26		)	145			108		38
Total impact to statement of operations	$	65		$	62		$	212	$	24

Reliant Energy's loss positions were acquired as of May 1, 2009, and valued using forward prices on that date. Green Mountain Energy's loss positions were acquired as of November 5, 2010, and valued using forward prices on that date. The roll-off amounts were offset by realized losses at the settled prices and are reflected in the cost of operations during the same period.

For the six months ended June 30, 2011, the unrealized gain from open economic hedge positions is 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.

For the six months ended June 30, 2010, the unrealized loss from open economic hedge positions is the result of a decrease in value of forward purchases and sales of natural gas, electricity and fuel due to a decrease in forward power and gas prices. This was partially offset by an increase in the value of forward sales of natural gas and electricity.

Credit Risk Related Contingent Features

Certain of the Company's hedging agreements contain provisions that require the Company to post additional collateral if the counterparty determines that there has been deterioration in credit quality, generally termed “adequate assurance” under the agreements, or require the Company to post additional collateral if there were a one notch downgrade in the Company's credit rating. The collateral required for contracts that have adequate assurance clauses that are in a net liability position as of June 30, 2011, was $45 million. The collateral required for contracts with credit rating contingent features was $38 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 $19 million as of June 30, 2011.

See Note 6, Fair Value of Financial Instruments, to this Form 10-Q for discussion regarding concentration of credit risk.

Note 9 — Long-Term Debt

This footnote should be read in conjunction with the complete description under Note 12, Debt and Capital Leases, to the Company's 2010 Form 10-K.

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



	June 30, 2011		December 31, 2010		Interest rate ^(a)
	(In millions, except rates)
NRG Recourse Debt:
Senior notes, due 2021	$	1,200	$	—	7.875
Senior notes, due 2020	1,100		1,100		8.250
Senior notes, due 2019	800		—		7.625
Senior notes, due 2019	691		690		8.500
Senior notes, due 2018	1,200		—		7.625
Senior notes, due 2017	1,100		1,100		7.375
Senior notes, due 2016	—		2,400		7.375
Senior notes, due 2014	—		1,205		7.250
Term loan facility, due 2013 - 2015 ^(b)	1,598		1,759		L+1.75 - L+3.25
Indian River Power LLC, tax-exempt bonds, due 2040	51		1		6.000
Indian River Power LLC, tax-exempt bonds, due 2045	111		66		5.375
Dunkirk Power LLC, tax-exempt bonds, due 2042	59		59		5.875
NRG Non-Recourse Debt:
NRG Peaker Finance Co. LLC, bonds, due 2019	209		206		L+1.07
NRG Energy Center Minneapolis LLC, senior secured notes, due 2013, 2017, and 2025	157		163		5.95 - 7.31
Solar Partners I, due 2014 and 2033	161		—		1.126 - 3.991
Solar Partners II, due 2014 and 2038	162		—		1.116 - 4.195
Solar Partners VIII, due 2014 and 2038	151		—		1.381 - 4.256
NRG Connecticut Peaking Development LLC, equity bridge loan facility, due 2011	—		61		L+2
NINA TANE facility	—		144		L+2
NINA Shaw facility	—		23		L+6
South Trent Wind LLC, financing agreement, due 2020	76		78		L+2.5
NRG Solar Blythe LLC, credit agreement, due 2028	29		29		L+2.5
Other	31		20		various
Subtotal long-term debt	8,886		9,104
Capital leases:
Saale Energie GmbH, Schkopau capital lease, due 2021	114		107
Subtotal	9,000		9,211
Less current maturities	90		463
Total long-term debt and capital leases	$	8,910	$	8,748
Funded letter of credit ^(b)	$	1,300	$	1,300	L+1.75 - L+3.25

(a) L+ equals LIBOR plus x%.

(b) On July 1, 2011, the Term loan facility and Funded letter of credit were repaid and replaced, as described below under Senior Credit Facility.

Issuance of 2018 Senior Notes

On January 26, 2011, NRG issued $1.2 billion aggregate principal amount at par of 7.625% Senior Notes due 2018, or 2018 Senior Notes. The 2018 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 2010 Form 10-K. The Indenture and the form of the note provide, among other things, that the 2018 Senior Notes will be senior unsecured obligations of NRG.

The net proceeds were used primarily to complete the tender offer of the 2014 Senior Notes. Interest is payable semi-annually beginning on July 15, 2011, until their maturity date of January 15, 2018.

Prior to maturity, NRG may redeem all or a portion of the 2018 Senior Notes at a redemption price equal to 100% of the principal amount of the notes redeemed plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the note or (ii) the excess of the present value of the principal amount at maturity plus all required interest payments due on the note through the maturity date discounted at a Treasury rate plus 0.50%.

Redemption of 2014 Senior Notes

On January 26, 2011, the Company redeemed $945 million of the 2014 Senior Notes through a tender offer, at an early redemption percentage of 102.063%. An additional $2 million was tendered at a redemption percentage of 100.063% and the remaining $253 million of 2014 Senior Notes were called on February 25, 2011, at a redemption percentage of 101.813%. A $28 million loss on the extinguishment of the 2014 Senior Notes was recorded during the three months ended March 31, 2011, which primarily consisted of the premiums paid on the redemption and the write-off of previously deferred financing costs.

Issuance of 7.625% 2019 Senior Notes and 2021 Senior Notes

On May 24, 2011, NRG issued $800 million aggregate principal amount at par of 7.625% Senior Notes due 2019, or the 7.625% 2019 Senior Notes, and $1.2 billion aggregate principal amount at par of 7.875% Senior Notes due 2021, or the 2021 Senior Notes. The 7.625% 2019 Senior Notes and the 2021 Senior Notes were issued under an Indenture, dated February 2, 2006, between NRG and Law Debenture Trust Company of New York, as trustee, as amended through Supplemental Indentures, which is discussed in Note 12, Debt and Capital Leases, in the Company's 2010 Form 10-K. The Indentures and the form of the notes provide, among other things, that the 7.625% 2019 Senior Notes and the 2021 Senior Notes will be senior unsecured obligations of NRG.

The net proceeds of $2 billion for both the 7.625% 2019 Senior Notes and the 2021 Senior Notes were used to complete the tender offer of the 2016 Senior Notes. Interest is payable semi-annually beginning on November 15, 2011, until their maturity dates of May 15, 2019, and May 15, 2021, respectively.

Prior to May 15, 2014, NRG may redeem up to 35% of the aggregate principal amount of the 7.625% 2019 Senior Notes with the net proceeds of certain equity offerings, at a redemption price of 107.625% of the principal amount. Prior to May 15, 2014, NRG may redeem all or a portion of the 7.625% 2019 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 103.813% of the note, plus interest payments due on the note from the date of redemption through May 15, 2014, discounted at a Treasury rate plus 0.50%. In addition, on or after May 15, 2014, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:



Redemption Period	Redemption Percentage
May 15, 2014 to May 14, 2015	103.813%
May 15, 2015 to May 14, 2016	101.906%
May 15, 2016 and thereafter	100.000%

Prior to May 15, 2016, NRG may redeem up to 35% of the aggregate principal amount of the 2021 Senior Notes with the net proceeds of certain equity offerings, at a redemption price of 107.875% of the principal amount. Prior to May 15, 2016, NRG may redeem all or a portion of the 2021 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 103.938% of the note, plus interest payments due on the note from the date of redemption through May 15, 2016, discounted at a Treasury rate plus 0.50%. In addition, on or after May 15, 2016, 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
May 15, 2016 to May 14, 2017	103.938%
May 15, 2017 to May 14, 2018	102.625%
May 15, 2018 to May 14, 2019	101.313%
May 15, 2019 and thereafter	100.000%

In connection with the 7.625% 2019 Senior Notes and the 2021 Senior Notes, NRG entered into a registration payment arrangement. For the 7.625% 2019 Senior Notes and the 2021 Senior Notes, 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 7.625% 2019 Senior Notes or the 2021 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% per annum of the principal amount of the 7.625% 2019 Senior Notes or the 2021 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 2016 Senior Notes

On May 23, 2011, the Company redeemed $1.7 billion of the 2016 Senior Notes through a tender offer, at an early redemption percentage of 103.938%. An additional $0.4 million was tendered at a redemption percentage of 102.938% and the remaining $666 million of 2016 Senior Notes was called on June 23, 2011, at a redemption percentage of 103.688%. A $115 million loss on the extinguishment of the 2016 Senior Notes was recorded during the six months ended June 30, 2011, which primarily consisted of the premiums paid on the redemption and the write-off of previously deferred financing costs.

Senior Credit Facility

Prepayment of Senior Credit Facility — In March 2011, NRG made a repayment of approximately $149 million to its first lien lenders under the Term Loan Facility. This payment resulted from the mandatory annual offer of a portion of NRG's excess cash flow (as defined in the Senior Credit Facility) for 2010.

2011 Senior Credit Facility — On July 1, 2011, NRG replaced its Senior Credit Facility, consisting of its Term Loan Facility, Revolving Credit Facility and Funded Letter of Credit Facility, with a new senior secured facility, or the 2011 Senior Credit Facility, which includes the following:

•

A $2.3 billion revolving credit facility with a maturity date of June 30, 2016, which will pay interest on amounts drawn at a rate of LIBOR plus 2.75%. In connection with the issuance of this revolving credit facility, the outstanding letters of credit were novated from the Funded Letter of Credit Facility to the new revolving credit facility. In addition, the related Funded Letter of Credit loan was repaid, the non-current restricted cash balance was returned to the lenders and the related balances were removed from NRG's balance sheet.

•

A $1.6 billion term loan facility with a maturity date of June 30, 2018, which will pay interest at a rate of LIBOR plus 3.00%, with a LIBOR floor of 1.00%. The debt was issued at 99.75% of face value; the discount will be amortized to interest expense over the life of the loan. Repayments under the new term loan facility will consist of 0.25% per quarter, with the remainder due at maturity. The proceeds of the new term loan facility were used to repay the existing term loan balance outstanding.

Indian River Power LLC Tax-Exempt Bonds

During the first half of 2011, the Company received additional proceeds of $45 million from the Delaware Economic Development Authority tax-exempt bond financing, and $50 million from the Sussex County, Delaware tax-exempt bond financing, bringing the total proceeds received as of June 30, 2011, to $111 million and $51 million, respectively.

Ivanpah Financing

On April 5, 2011, NRG acquired a majority interest in Ivanpah, as discussed in Note 4, Business Acquisitions and Disposition. On April 5, 2011, Ivanpah entered into an agreement with the Federal Financing Bank, or FFB, to borrow up to $1.6 billion to finance the costs of constructing the Ivanpah solar facility, or the Ivanpah Credit Agreement. Each phase of the project is governed by a separate financing agreement and is non recourse to both the other projects and to NRG. Funding requests are submitted to the FFB on a monthly basis and the loans provided by the FFB are guaranteed by the U.S. DOE. Amounts borrowed under the Ivanpah Credit Agreement accrue interest at a fixed rate based on U.S. Treasury rates plus a spread of 0.375% and are secured by all the assets of Ivanpah. Ivanpah intends to submit an application to the U.S. Department of Treasury for a cash grant; any proceeds received will be utilized to repay the borrowings that mature in 2014.

The following table reflects the borrowings under the FFB Credit Agreement as of June 30, 2011:



	Maximum borrowings available under FFB Credit Agreement		Amounts borrowed		Weighted average interest rate on amounts borrowed
	(In millions, except rates)
Solar Partners I, due June 27, 2014 ^(a)	$	159	$	152	1.677	%
Solar Partners I, due June 27, 2033	392		9		3.991	%
Solar Partners II, due February 27, 2014 ^(a)	132		128		1.609	%
Solar Partners II, due February 27, 2038	387		34		4.183	%
Solar Partners VIII, due October 27, 2014 ^(a)	117		111		1.996	%
Solar Partners VIII, due October 27, 2038	440		40		4.229	%
	$	1,627	$	474

(a) The cash portion of the loan is fully drawn; additional amounts will be utilized for capitalized interest.

Roadrunner Financing

On May 25, 2011, NRG, through its wholly-owned subsidiary, NRG Roadrunner LLC, or Roadrunner, entered into a credit agreement with a bank, or the Roadrunner Financing Agreement, for a $47 million construction loan that converts to a term loan upon commencing commercial operations and a $21 million cash grant loan, both of which have an interest rate of LIBOR plus an applicable margin of 2.01%. The construction and term loans, which will be drawn upon first, have an interest rate of LIBOR plus an applicable margin which escalates 0.25% every five years and ranges from 2.01% at closing to 2.76% in year fifteen through maturity. The term loan, which is secured by all the assets of Roadrunner, matures on November 30, 2031, and amortizes based upon a predetermined schedule. The cash grant loan matures upon the earlier of the receipt of the cash grant or May 2012. The Roadrunner Financing Agreement also includes a letter of credit facility on behalf of Roadrunner of up to $5 million. Roadrunner pays an availability fee of 100% of the applicable margin on issued letters of credit. As of June 30, 2011, $9 million was outstanding under the construction and term loan and $2 million letters of credit in support of the PPA were issued.

Also related to the Roadrunner Financing Agreement, in April 2011, Roadrunner entered into a fixed for floating interest rate swap for 75% of the outstanding term loan amount, intended to hedge the risks associated with floating interest rates. Roadrunner will pay its counterparty the equivalent of a 4.313% fixed interest payment on a predetermined notional value, and Roadrunner will receive quarterly the equivalent of a floating interest payment based on a three month LIBOR calculated on the same notional value. All interest rate swap payments by Roadrunner 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 matures in December 2029, is $36 million and amortizes in proportion to the loan. The swap is forward starting and effective September 30, 2011.

NRG CT Peaking

On June 29, 2011, NRG Connecticut Peaking Development LLC repaid the $61 million outstanding under the equity bridge loan facility, or EBL. The commitment was terminated and the collateral held under the facility, including the letter of credit issued by NRG under the Funded Letter of Credit Facility, has been returned. The EBL was used to fund the majority of the equity portion of the GenConn Energy LLC investment.

Note 10 — Variable Interest Entities, or VIEs

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

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 $93 million as of June 30, 2011.

GenConn Energy LLC — Through its subsidiary, NRG Connecticut Peaking Development LLC, NRG owns a 50% interest in GenConn, a limited liability company formed to construct, own and operate two 200 MW peaking generation facilities in Connecticut at NRG's Devon and Middletown sites. The GenConn Devon facility reached commercial operation in 2010. Construction of the Middletown facility is substantially complete with all four generating units becoming operational and participating in the ISONE market in June 2011.

NRG Connecticut Peaking Development LLC had a note receivable due from GenConn for $63 million as of June 30, 2011 as discussed in Note 9, Capital Leases and Notes Receivable to the Company's 2010 Form 10-K. As of June 30, 2011, NRG had a $69 million equity investment in GenConn. NRG's maximum exposure to loss is limited to its equity investment and note receivable.

Note 11 — Changes in Capital Structure

As of June 30, 2011, and December 31, 2010, 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, 2010	304,006,027	(56,808,672	)	247,197,355
Shares issued under LTIP	103,289	—		103,289
Shares issued under ESPP	—	65,717		65,717
Capital Allocation Plan repurchases	—	(6,229,574	)	(6,229,574	)
Balance as of June 30, 2011	304,109,316	(62,972,529	)	241,136,787

2011 Capital Allocation Plan

On February 22, 2011, the Company announced a plan to repurchase $180 million of common stock under the Company's 2011Capital Allocation Plan. The Company entered into an accelerated share repurchase agreement, or ASR Agreement, with a financial institution to repurchase a total of $130 million of NRG common stock, based on a volume weighted average price less a specified discount. On February 25, 2011, the Company remitted $130 million to the financial institution. The share repurchases under the ASR Agreement were completed on April 29, 2011, and the Company received 6,229,574 shares of NRG common stock. On August 4 2011, the Company announced additional share repurchases of $250 million under the Capital Allocation Plan, bringing the total targeted share repurchases for 2011 to $430 million. The Company intends to complete its remaining $300 million of share repurchases by the end of 2011, subject to market prices, financial restrictions under the Company's debt facilities and as permitted by securities laws.

Employee Stock Purchase Plan

In July 2011, 54,410 shares of NRG common stock were issued to employee accounts from treasury stock under the ESPP.

Note 12 — Earnings Per Share

Basic earnings per common share is computed by dividing net income less accumulated preferred stock dividends by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the year are weighted for the portion of the year that they were outstanding. Diluted earnings per share is computed in a manner consistent with that of basic earnings per share while giving effect to all potentially dilutive common shares that were outstanding during the period. Shares borrowed under the Share Lending Agreement (see Note 15, Capital Structure — Share Lending Agreements in the Company's 2010 Form 10-K) were not treated as outstanding for earnings per share purposes.

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



	Three months ended June 30,						Six months ended June 30,
(In millions, except per share data)	2011			2010			2011			2010
Basic earnings per share attributable to NRG common stockholders
Numerator:
Net income attributable to NRG Energy, Inc.	$	621		$	211		$	361		$	269
Preferred stock dividends	(3		)	(3		)	(5		)	(5		)
Net income attributable to NRG Energy, Inc. available to common stockholders	$	618		$	208		$	356		$	264
Denominator:
Weighted average number of common shares outstanding	243			255			245			254
Basic earnings per share:
Net income attributable to NRG Energy, Inc.	$	2.54		$	0.82		$	1.45		$	1.04
Diluted earnings per share attributable to NRG common stockholders
Numerator:
Net income attributable to NRG Energy, Inc. available to common stockholders	$	618		$	208		$	356		$	264
Denominator:
Weighted average number of common shares outstanding	243			255			245			254
Incremental shares attributable to the issuance of equity compensation (treasury stock method)	1			1			2			1
Incremental shares attributable to assumed conversion features of outstanding preferred stock (if-converted method)	—			—			—			1
Total dilutive shares	244			256			247			256
Diluted earnings per share:
Net income attributable to NRG Energy, Inc.	$	2.53		$	0.81		$	1.44		$	1.03

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



	Three months ended June 30,		Six months ended June 30,
(In millions of shares)	2011	2010	2011	2010
Equity compensation — NQSOs and PUs	7	6	7	6
Embedded derivative of 3.625% redeemable perpetual preferred stock	16	16	16	16
Total	23	22	23	22

Note 13 — Segment Reporting

NRG's segment structure reflects core areas of operation which are primarily segregated based on the Company's wholesale power generation, retail, thermal and chilled water business, and corporate activities. Within NRG's wholesale power generation operations, there are distinct components with separate operating results and management structures for the following geographical regions: Texas, Northeast, South Central, West and International. The Company's corporate activities include solar and wind development, NINA activity and Green Mountain Energy. Intersegment supply sales between Texas, Reliant Energy and Green Mountain Energy are accounted for at market.



(In millions)			Wholesale Power Generation
Three months ended June 30, 2011	Reliant Energy		Texas^(a)		Northeast		South Central		West		Internat- ional		Thermal			Corporate^(b)(c)			Elimination			Total
Operating revenues	$	1,264	$	822	$	246	$	188	$	38	$	38	$	32		$	161		$	(511	)	$	2,278
Depreciation and amortization	24		122		27		22		3		—		4			20			—			222
Equity in earnings of unconsolidated affiliates	—		2		3		—		5		2		—			—			—			12
Income/(loss) before income taxes	31		203		19		12		12		8		(2		)	(292		)	—			(9		)
Net income/(loss) attributable to NRG Energy, Inc.	$	31	$	203	$	19	$	12	$	12	$	6	$	(2	)	$	340		$	—		$	621
Total assets	$	1,519	$	12,760	$	1,914	$	1,312	$	1,430	$	798	$	344		$	19,951		$	(14,692	)	$	25,336


(a)	Includes inter-segment sales of $456 million to Reliant Energy and $50 million to Green Mountain Energy.


(b)	Includes Green Mountain Energy results.


(c)	Includes an impairment charge on investment of $11 million.



(In millions)			Wholesale Power Generation
Three months ended June 30, 2010	Reliant Energy		Texas^(d)			Northeast			South Central		West		Internat- ional		Thermal			Corporate			Elimination			Total
Operating revenues	$	1,282	$	692		$	205		$	152	$	32	$	30	$	27		$	(4	)	$	(283	)	$	2,133
Depreciation and amortization	29		124			31			16		3		—		3			2			—			208
Equity in earnings/(losses) of unconsolidated affiliates	—		1			(1		)	—		1		11		—			(1		)	—			11
(Loss)/income before income taxes	277		157			(2		)	4		8		31		(2		)	(147		)	1			327
Net loss attributable to non-controlling interest	—		(1		)	—			—		—		—		—			—			—			(1		)
Net income/(loss) attributable to NRG Energy, Inc.	$	277	$	158		$	(2	)	$	4	$	8	$	21	$	(2	)	$	(254	)	$	1		$	211

(d) Includes inter-segment sales of $281 million to Reliant Energy.



(In millions)			Wholesale Power Generation
Six months ended June 30, 2011	Reliant Energy		Texas^(a)			Northeast			South Central		West		Internat- ional		Thermal		Corporate^(b)(c)			Elimination			Total
Operating revenues	$	2,269	$	1,353		$	472		$	377	$	80	$	73	$	72	$	283		$	(706	)	$	4,273
Depreciation and amortization	48		244			56			42		6		—		7		24			—			427
Equity in (losses)/earnings of unconsolidated affiliates	—		(6		)	5			—		5		6		—		—			—			10
Income/(loss) before income taxes	303		210			(13		)	26		25		18		3		(946		)	—			(374		)
Net income/(loss) attributable to NRG Energy, Inc.	$	303	$	210		$	(13	)	$	26	$	25	$	14	$	3	$	(207	)	$	—		$	361


(a)	Includes inter-segment sales of $633 million to Reliant Energy and $66 million to Green Mountain Energy.


(b)	Includes Green Mountain Energy results.


(c)	Includes an impairment charge on investment of $492 million.



(In millions)			Wholesale Power Generation
Six months ended June 30, 2010	Reliant Energy		Texas ^(d)			Northeast			South Central		West		Internat-ional		Thermal		Corporate			Elimination			Total
Operating revenues	$	2,458	$	1,562		$	484		$	295	$	67	$	65	$	63	$	(2	)	$	(644	)	$	4,348
Depreciation and amortization	59		241			63			32		6		—		5		4			—			410
Equity in earnings/(losses) of unconsolidated affiliates	—		11			(1		)	—		1		15		—		(1		)	—			25
Income/(loss) before income taxes	89		532			50			—		14		41		2		(279		)	1			450
Net loss attributable to non-controlling interest	—		(1		)	—			—		—		—		—		—			—			(1		)
Net income/(loss)attributable to NRG Energy, Inc.	$	89	$	533		$	50		$	—	$	14	$	29	$	2	$	(449	)	$	1		$	269

(d) Includes inter-segment sales of $642 million to Reliant Energy.

Note 14 — Income Taxes

Effective Tax Rate

The income tax provision consisted of the following:



	Three months ended June 30,						Six months ended June 30,
(In millions except otherwise noted)	2011			2010			2011			2010
Income tax (benefit)/expense	$	(630	)	$	117		$	(735	)	$	182
Effective tax rate	7,000.0		%	35.8		%	196.5		%	40.4		%

For the three and six months ended June 30, 2011, NRG recorded an income tax benefit on pre-tax losses of $9 million and $374 million, respectively. NRG's overall effective tax rates for both of these periods were different than the statutory rate of 35% primarily due to a benefit of $612 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 in June 2011 and that were mainly composed of net operating losses of $536 million which had been classified as capital loss carryforwards for financial statement purposes. In addition, valuation allowance net decreases of $40 million and $23 million for the three and six month periods, respectively, increased the effective tax rates. For both the three and six months ended June 30, 2010, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to state and local income taxes, as well as recording federal and state tax expense and interest for uncertain tax benefits.

Uncertain tax benefits

As of June 30, 2011, a non-current tax liability of $53 million for uncertain tax benefits remains from positions taken on various state tax returns, including accrued interest. NRG has accrued interest and penalties related to these uncertain tax benefits of $1 million for the six months ended June 30, 2011, and has accrued $9 million since adoption. The Company recognizes interest and penalties related to uncertain tax benefits in income tax expense.

The Company continues to be under examination for various state jurisdictions for multiple years.

Tax Receivable and Payable

As of June 30, 2011, NRG recorded a current tax payable of $20 million that represents a tax liability due for domestic state taxes of $15 million, as well as foreign taxes payable of $5 million. In addition, as of June 30, 2011, NRG has a domestic tax receivable of $95 million, of which $89 million is related to property tax refunds as a result of the New York State Empire Zone program.

Note 15 — Benefit Plans and Other Postretirement Benefits

NRG sponsors and operates three defined benefit pension and other postretirement plans. In addition, NRG has a 44% undivided ownership interest in STP 1 & 2. South Texas Project Nuclear Operating Company, or STPNOC, which operates and maintains STP 1 & 2, provides its employees a defined benefit pension plan as well as postretirement health and welfare benefits. Although NRG does not sponsor the South Texas Project plans, it reimburses STPNOC for 44% of the contributions made towards its retirement plan obligations.

The total amount of employer contributions paid for the six months ended June 30, 2011, including reimbursements to STPNOC, was $16 million. NRG expects to make approximately $9 million in contributions for the remainder of 2011. Relating to its sponsored plans as well as its 44% interest in STP 1 & 2, the Company recognized total net periodic benefit cost of $9 million and $19 million for the three and six months ended June 30, 2011, respectively, and $7 million and $15 million for the three and six months ended June 30, 2010, respectively.

Note 16 — Commitments and Contingencies

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 June 30, 2011, all hedges under the first liens were in-the-money for NRG on a counterparty aggregate basis.

Contingencies

Set forth below is a description of the Company's material legal proceedings. The Company believes that it has valid defenses to these legal proceedings and intends to defend them vigorously. Pursuant to the requirements of ASC 450 and related guidance, NRG records reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. In addition, legal costs are expensed as incurred. Management has assessed each of the following matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, the Company is unable to predict the outcome of these legal proceedings or reasonably estimate the scope or amount of any associated costs and potential liabilities. As additional information becomes available, management adjusts its assessment and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of the Company's liabilities and contingencies could be at amounts that are different from its currently recorded reserves and that such difference could be material.

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

California Department of Water Resources

This matter concerns, among other contracts and other defendants, the California Department of Water Resources, or CDWR, and its wholesale power contract with subsidiaries of WCP (Generation) Holdings, Inc., or WCP. The case originated with a February 2002 complaint filed by the State of California alleging that many parties, including WCP subsidiaries, overcharged the State of California. For WCP, the alleged overcharges totaled approximately $940 million for 2001 and 2002. The complaint demanded that the Federal Energy Regulatory Commission, or FERC, abrogate the CDWR contract and sought refunds associated with revenues collected under the contract. In 2003, the FERC rejected this complaint, denied rehearing, and the case was appealed to the U.S. Court of Appeals for the Ninth Circuit where oral argument was held on December 8, 2004. On December 19, 2006, the Ninth Circuit decided that in the FERC's review of the contracts at issue, the FERC could not rely on the Mobile-Sierra standard presumption of just and reasonable rates, where such contracts were not reviewed by the FERC with full knowledge of the then existing market conditions. WCP and others sought review by the U.S. Supreme Court. WCP's appeal was not selected, but instead held by the Supreme Court. In the appeal that was selected by the Supreme Court, on June 26, 2008, the Supreme Court ruled: (i) that the Mobile-Sierra public interest standard of review applied to contracts made under a seller's market-based rate authority; (ii) that the public interest “bar” required to set aside a contract remains a very high one to overcome; and (iii) that the Mobile-Sierra presumption of contract reasonableness applies when a contract is formed during a period of market dysfunction unless (a) such market conditions were caused by the illegal actions of one of the parties or (b) the contract negotiations were tainted by fraud or duress. In this related case, the U.S. Supreme Court affirmed the Ninth Circuit's decision agreeing that the case should be remanded to the FERC to clarify the FERC's 2003 reasoning regarding its rejection of the original complaint relating to the financial burdens under the contracts at issue and to alleged market manipulation at the time these contracts were formed. As a result, the U.S. Supreme Court then reversed and remanded the WCP CDWR case to the Ninth Circuit for treatment consistent with its June 26, 2008, decision in the related case. On October 20, 2008, the Ninth Circuit asked the parties in the remanded CDWR case, including WCP and the FERC, whether that Court should answer a question the U.S. Supreme Court did not address in its June 26, 2008, decision; whether the Mobile-Sierra doctrine applies to a third-party that was not a signatory to any of the wholesale power contracts, including the CDWR contract, at issue in that case. Without answering that reserved question, on December 4, 2008, the Ninth Circuit vacated its prior opinion and remanded the WCP CDWR case back to the FERC for proceedings consistent with the U.S. Supreme Court's June 26, 2008, decision.

On December 15, 2008, WCP and the other seller-defendants filed with the FERC a Motion for Order Governing Proceedings on Remand. On January 14, 2009, the Public Utilities Commission of the State of California filed an Answer and Cross Motion for an Order Governing Procedures on Remand and on January 28, 2009, WCP and the other seller-defendants filed their reply. At this time, the FERC has not acted on remand.

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

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

Louisiana Generating, LLC

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

On April 27, 2009, LaGen made several filings. LaGen filed an objection in the Cajun Electric Cooperative Power, Inc.'s bankruptcy proceeding in the U.S. Bankruptcy Court for the Middle District of Louisiana to seek to prevent the bankruptcy from closing. LaGen also filed a complaint, or adversary proceeding, in the same bankruptcy proceeding, seeking a judgment that: (i) it did not assume liability from Cajun Electric for any claims or other liabilities under environmental laws with respect to Big Cajun II that arose, or are based on activities that were undertaken, prior to the closing date of the acquisition; (ii) it is not otherwise the successor to Cajun Electric with respect to 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 June 8, 2009, the parties filed a joint status report in the U.S. DOJ lawsuit setting forth their views of the case and proposing a trial schedule. While the district court entered a Joint Case Management Order on April 28, 2010, indicating the potential of a 2011 liability phase trial, no such trial date has been set.

On August 24, 2009, LaGen filed a motion to dismiss this lawsuit, and on September 25, 2009, the U.S. DOJ filed its opposition to the motion. Thereafter, on February 18, 2010, the Louisiana Department of Environmental Quality, or LDEQ, filed a motion to intervene in the above lawsuit and a complaint against LaGen for alleged violations of Louisiana's Prevention of Significant Deterioration, or PSD, regulations and Louisiana's Title V operating permit program. LDEQ seeks substantially similar relief to that requested by the U.S. DOJ. On February 19, 2010, the district court granted LDEQ's motion to intervene. On April 26, 2010, LaGen filed a motion to dismiss the LDEQ complaint. On July 21, 2010, the motions to dismiss the U.S. DOJ and LDEQ complaints were argued to the district court. On August 20, 2010, the parties submitted proposed findings of fact and conclusions of law, and both parties have submitted additional briefing on emerging jurisprudence from other jurisdictions touching on the issues at stake in the U.S. DOJ lawsuit. On February 4, 2011, LaGen filed motions for summary judgment requesting that the court dismiss all of the U.S. DOJ's claims. Also on February 4, 2011, the U.S. DOJ filed three motions for partial summary judgment. Additional summary judgment briefing was filed by the parties on April 4, 2011. On April 20, 2011, the district court ruled that certain of the liability phase deadlines were vacated until the court ruled on the summary judgment motions submitted by the parties. A status conference is scheduled with the magistrate judge for August 5, 2011.

Excess Mitigation Credits

From January 2002 to April 2005, CenterPoint Energy applied excess mitigation credits, or EMCs, to its monthly charges to retail electric providers as ordered by the PUCT. The PUCT imposed these credits to facilitate the transition to competition in Texas, which had the effect of lowering the retail electric providers' monthly charges payable to CenterPoint Energy. As indicated in its Petition for Review filed with the Supreme Court of Texas on June 2, 2008, CenterPoint Energy has claimed that the portion of those EMCs credited to Reliant Energy Retail Services, LLC, or RERS, a retail electric provider and NRG subsidiary acquired from RRI Energy, Inc. (formerly Reliant Energy, Inc.), totaled $385 million for RERS's “Price to Beat” Customers. It is unclear what the actual number may be. “Price to Beat” was the rate RERS was required by state law to charge residential and small commercial customers that were transitioned to RERS from the incumbent integrated utility company commencing in 2002. In its original stranded cost case brought before the PUCT on March 31, 2004, CenterPoint Energy sought recovery of all EMCs that were credited to all retail electric providers, including RERS, and the PUCT ordered that relief in its Order on Rehearing in Docket No. 29526, on December 17, 2004. After an appeal to state district court, the court entered a final judgment on August 26, 2005, affirming the PUCT's order with regard to EMCs credited to RERS. Various parties filed appeals of that judgment, and on April 17, 2008, the Court of Appeals for the Third District reversed the lower court's decision ruling that CenterPoint Energy's stranded cost recovery should exclude only EMCs credited to RERS for its “Price to Beat” customers. On June 2, 2008, CenterPoint Energy's Petition for Review with the Supreme Court of Texas was accepted. Oral argument occurred on October 6, 2009, and on March 18, 2011, the Texas Supreme Court reversed the Court of Appeals, finding no basis for deducting EMCs credited to RERS. Motions for rehearing were filed on May 4, 2011. On June 10, 2011, the Texas Supreme Court denied all motions for rehearing, thereby ending the matter.

In November 2008, CenterPoint Energy and Reliant Energy Inc., or REI, on behalf of itself and affiliates including RERS, agreed to suspend unexpired deadlines, if any, related to limitations periods that might exist for possible claims against REI and its affiliates if CenterPoint Energy is ultimately not allowed to include in its stranded cost calculation those EMCs previously credited to RERS. The agreed upon suspension of unexpired deadlines will cease by August 29, 2011. NRG believes that any possible future CenterPoint Energy claim against RERS for EMCs credited to RERS would lack legal merit. No such claim has been filed.

Note 17 — Regulatory Matters

NRG operates in a highly regulated industry and is subject to regulation by various federal and state agencies. As such, NRG is affected by regulatory developments at both the federal and state levels and in the regions in which NRG operates. In addition, NRG is subject to the market rules, procedures, and protocols of the various ISO markets in which NRG participates. These power markets are subject to ongoing legislative and regulatory changes that may impact NRG's wholesale and retail businesses.

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

California — On May 4, 2010, in Southern California Edison Company v. FERC, the U.S. Court of Appeals for the D.C. Circuit vacated FERC's acceptance of station power rules for the CAISO market, and remanded the case for further proceedings at FERC. On August 30, 2010, FERC issued an Order on Remand effectively disclaiming jurisdiction over how the states impose retail station power charges. Due to reservation-of-rights language in the California utilities' state-jurisdictional station power tariffs, FERC's ruling 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, FERC issued an order denying rehearing. The Company, together with other generators, has filed an appeal. On April 22, 2011, Southern California Edison Company filed with the California Public Utilities Commission seeking authorization to begin charging generators station power charges, and to assess such charges retroactively, which the Company and other generators have challenged. The Company 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. 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. If all appeals are unsuccessful, on remand to the PUCT, it would determine the appropriate methodology for giving effect to the trial court's decision. It is not known at this time whether only Constellation's under-scheduling charges, the under-scheduling charges of all other Qualified Scheduling Entities, or QSEs, that disputed REPS charges for the same time frame, the entire market, or some other approach would be used for any resettlement.

Under the PUCT ordered formula 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.

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, FERC eliminated certain regional through-and-out transmission rates charged by transmission owners in the regional electric grids operated by the Midwest Independent Transmission Systems Operator, Inc. and PJM Interconnection, L.L.C., or PJM, respectively. In order to temporarily compensate the transmission owners for revenue lost as a result of the elimination of the through-and-out transmission rates, 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 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, FERC issued two orders. In its Order on Rehearing, 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, 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. Requests for rehearing are pending of the Order on Initial Decision. Several parties have filed notices of appeal of the Order on Rehearing, which are being held in abeyance pending resolution of the requests for rehearing before FERC.

With regard to the SECA charges that had been invoiced to Green Mountain Energy, 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 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 has established an appropriate reserve.

Note 18 — 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 laws have become increasingly stringent and NRG expects this trend to continue. The electric generation industry will face new requirements to address air emissions, climate change, combustion byproducts and water use. In general, future laws and regulations are expected to require the addition of emission controls or other environmental quality equipment or the imposition of certain restrictions on the operations of the Company's facilities. NRG expects that future liability under, or compliance with, environmental requirements could have a material effect on the Company's operations or competitive position.

Environmental Capital Expenditures

Based on current rules, technology and plans, NRG has estimated that environmental capital expenditures from 2011 through 2015 to meet NRG's environmental commitments will be approximately $721 million (of which $180 million will be financed through draws on the Indian River tax exempt facilities) and are primarily associated with controls on the Company's Big Cajun and Indian River facilities. These capital expenditures, in general, are related to installation of particulate, SO₂, NO_x, and mercury controls to comply with federal and state air quality rules and consent orders, as well as installation of Best Technology Available, or BTA, under the proposed 316(b) Rule. NRG continues to explore cost effective compliance alternatives. This estimate reflects anticipated schedules and controls related to CAIR, Mercury and Air Toxics Standards and the 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; however, NRG believes it is positioned to meet more stringent requirements through its planned capital expenditures, existing controls, and the use of Powder River Basin coal.

The U.S. EPA released the final Cross-State Air Pollution Rule, or CSAPR, on July 7, 2011. CSAPR will replace CAIR and is designed to bring 27 states and Washington, D.C. into attainment with PM 2.5 and ozone national ambient air quality standards, or NAAQS, reducing SO₂ and NO_x emissions from power plants. Under CSAPR, use of discounted Acid Rain SO₂ and CAIR NO_x allowances will be discontinued and replaced with completely distinct allowance programs. Acid Rain allowances will still be required on a 1:1 basis under the Acid Rain Program. NRG owns or has minority interests in plants in six states that are covered by the rule. NRG is reviewing the recent rule and developing an integrated strategy based on enhancing the performance of existing controls, fuel adjustments, other operational changes, and allowance acquisition. While it is still early in the review process, we do not expect any incremental environmental capital investment to be material. In the second half of 2011, this rule will result in an impairment charge ranging from $150 million to $200 million on the Company's excess Acid Rain Program SO₂ emission allowances, which are recorded as an intangible asset on the Company's balance sheet.

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 regions' 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 completed, the Company is unable to predict the impact of any required remediation. On May 29, 2008, DNREC requested that NRG's Indian River Operations, Inc. participate in the development and performance of a Natural Resource Damage Assessment, or NRDA, at the Burton Island Old Ash Landfill. NRG is currently working with DNREC and other trustees to close out the assessment phase.

Pursuant to a consent order dated September 25, 2007, and amended July 21, 2010, between NRG and DNREC regarding the Indian River plant, NRG agreed to limit the emissions of NO_x and SO₂, and to mothball Units 1 and 2. Unit 1 was mothballed as planned on May 1, 2011.

South Central Region

On February 11, 2009, the U.S. DOJ acting at the request of the U.S. EPA commenced a lawsuit against LaGen in federal district court in the Middle District of Louisiana alleging violations of the CAA at the Big Cajun II power plant. This is the same matter for which NOVs were issued to LaGen on February 15, 2005, and on December 8, 2006. Further discussion on this matter can be found in Note 16, Commitments and Contingencies — Louisiana Generating, LLC, to this Form 10-Q.

Note 19 — Condensed Consolidating Financial Information

As of June 30, 2011, the Company had outstanding $1.1 billion of 7.375% Senior Notes due 2017, $1.2 billion of 7.625% Senior Notes due 2018, $700 million of 8.50% Senior Notes due 2019, $800 million of 7.625% Senior Notes due 2019, $1.1 billion of 8.25% Senior Notes due 2020 and $1.2 billion of 7.875% Senior Notes due 2021. These notes are guaranteed by certain of NRG's current and future wholly-owned domestic subsidiaries, or guarantor subsidiaries.

Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of June 30, 2011:



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

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

The following condensed consolidating financial information presents the financial information of NRG 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 June 30, 2011



(In millions)	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
Operating Revenues
Total operating revenues	$	2,185		$	90		$	—		$	3		$	2,278
Operating Costs and Expenses
Cost of operations	1,545			59			1			3			1,608
Depreciation and amortization	210			8			4			—			222
Selling, general and administrative	93			7			67			—			167
Development costs	—			—			12			—			12
Total operating costs and expenses	1,848			74			84			3			2,009
Operating Income/(Loss)	337			16			(84		)	—			269
Other Income/(Expense)
Equity in earnings/(losses) of consolidated subsidiaries	6			(8		)	175			(173		)	—
Equity in earnings of unconsolidated affiliates	6			6			—			—			12
Impairment charge on investment	(11		)	—			—			—			(11		)
Other income, net	—			1			2			—			3
Loss on debt extinguishment	—			—			(115		)	—			(115		)
Interest expense	(17		)	(14		)	(136		)	—			(167		)
Total other expense	(16		)	(15		)	(74		)	(173		)	(278		)
(Loss)/Income Before Income Taxes	321			1			(158		)	(173		)	(9		)
Income tax (benefit)/expense	148			1			(779		)	—			(630		)
Net Income/(Loss) attributable to NRG Energy, Inc.	$	173		$	—		$	621		$	(173	)	$	621


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Six Months Ended June 30, 2011



(In millions)	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
Operating Revenues
Total operating revenues	$	4,089		$	194		$	—		$	(10	)	$	4,273
Operating Costs and Expenses
Cost of operations	2,798			131			6			(3		)	2,932
Depreciation and amortization	402			18			7			—			427
Selling, general and administrative	174			12			124			—			310
Development costs	—			(1		)	22			—			21
Total operating costs and expenses	3,374			160			159			(3		)	3,690
Operating Income/(Loss)	715			34			(159		)	(7		)	583
Other Income/(Expense)
Equity in earnings/(losses) of consolidated subsidiaries	15			(9		)	97			(103		)	—
Equity in losses of unconsolidated affiliates	6			4			—			—			10
Impairment charge on investment	(492		)	—			—			—			(492		)
Other income, net	—			5			3			—			8
Loss on debt extinguishment	—			—			(143		)	—			(143		)
Interest expense	(26		)	(27		)	(287		)	—			(340		)
Total other expense	(497		)	(27		)	(330		)	(103		)	(957		)
(Loss)/Income Before Income Taxes	218			7			(489		)	(110		)	(374		)
Income tax (benefit)/expense	112			3			(850		)	—			(735		)
Net Income attributable to NRG Energy, Inc.	$	106		$	4		$	361		$	(110	)	$	361


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

June 30, 2011



(In millions)	Guarantor Subsidiaries		Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
ASSETS
Current Assets
Cash and cash equivalents	$	20	$	160		$	1,759		$	—		$	1,939
Funds deposited by counterparties	260		—			—			—			260
Restricted cash	4		71			70			—			145
Accounts receivable, net	971		37			—			—			1,008
Inventory	377		9			—			—			386
Derivative instruments valuation	1,749		—			—			—			1,749
Cash collateral paid in support of energy risk management activities	254		—			—			—			254
Prepayments and other current assets	165		54			1,269			(1,190		)	298
Total current assets	3,800		331			3,098			(1,190		)	6,039
Net property, plant and equipment	10,666		1,584			50			(17		)	12,283
Other Assets
Investment in subsidiaries	288		412			13,884			(14,584		)	—
Equity investments in affiliates	52		497			—			—			549
Notes receivable – affiliate and capital leases, less current portion	—		419			404			(404		)	419
Goodwill	1,863		—			—			—			1,863
Intangible assets, net	1,529		65			33			(38		)	1,589
Nuclear decommissioning trust fund	433		—			—			—			433
Derivative instruments valuation	586		—			—			—			586
Restricted cash supporting Funded Letter of Credit Facility	—		1,301			—			—			1,301
Other non-current assets	42		52			180			—			274
Total other assets	4,793		2,746			14,501			(15,026		)	7,014
Total Assets	$	19,259	$	4,661		$	17,649		$	(16,233	)	$	25,336
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	1,150	$	64		$	26		$	(1,150	)	$	90
Accounts payable	357		155			330			—			842
Derivative instruments valuation	1,317		2			—			—			1,319
Deferred income taxes	524		(51		)	(372		)	—			101
Cash collateral received in support of energy risk management activities	260		—			—			—			260
Accrued expenses and other current liabilities	294		28			211			(40		)	493
Total current liabilities	3,902		198			195			(1,190		)	3,105
Other Liabilities
Long-term debt and capital leases	221		1,431			7,662			(404		)	8,910
Funded letter of credit	—		—			1,300			—			1,300
Nuclear decommissioning reserve	326		—			—			—			326
Nuclear decommissioning trust liability	278		—			—			—			278
Deferred income taxes	1,483		279			(53		)	—			1,709
Derivative instruments valuation	259		37			37			—			333
Out-of-market contracts	226		6			—			(31		)	201
Other non-current liabilities	485		23			90			—			598
Total non-current liabilities	3,278		1,776			9,036			(435		)	13,655
Total liabilities	7,180		1,974			9,231			(1,625		)	16,760
3.625% Preferred Stock	—		—			248			—			248
Stockholders’ Equity	12,079		2,687			8,170			(14,608		)	8,328
Total Liabilities and Stockholders’ Equity	$	19,259	$	4,661		$	17,649		$	(16,233	)	$	25,336


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2011



(In millions)	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
Cash Flows from Operating Activities
Net income	$	106		$	4		$	361		$	(110	)	$	361
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	(21		)	15			(93		)	99			—
Depreciation and amortization	402			18			7			—			427
Provision for bad debts	20			—			—			—			20
Amortization of nuclear fuel	20			—			—			—			20
Amortization of financing costs and debt discount/premiums	—			3			13			—			16
Loss on debt extinguishment	—			—			26			—			26
Amortization of intangibles and out-of-market contracts	92			—			—			—			92
Changes in deferred income taxes and liability for uncertain tax benefits	111			3			(862		)	—			(748		)
Changes in nuclear decommissioning trust liability	13			—			—			—			13
Changes in derivatives	(167		)	1			—			—			(166		)
Changes in collateral deposits supporting energy risk management activities	67			2			—			—			69
Impairment charge on investment	481			—			—			—			481
Cash (used)/provided by changes in other working capital	(273		)	7			(43		)	7			(302		)
Net Cash Provided/(Used) by Operating Activities	851			53			(591		)	(4		)	309
Cash Flows from Investing Activities
Intercompany loans to subsidiaries	(869		)	(14		)	(352		)	1,235			—
Acquisition of businesses, net of cash acquired	—			(68		)	—			—			(68		)
Capital expenditures	(197		)	(599		)	(43		)	—			(839		)
Increase in restricted cash, net	(1		)	(41		)	—			—			(42		)
Increase in restricted cash - U.S. DOE projects	—			—			(70		)	—			(70		)
Decrease in notes receivable	—			20			—			—			20
Purchases of emission allowances	(17		)	—			—			—			(17		)
Proceeds from sale of emission allowances	4			—			—			—			4
Investments in nuclear decommissioning trust fund securities	(165		)	—			—			—			(165		)
Proceeds from sales of nuclear decommissioning trust fund securities	152			—			—			—			152
Proceeds from sale of assets	13			—			—			—			13
Investments in unconsolidated affiliates	(1		)	(14		)	—			—			(15		)
Other	(6		)	(16		)	(10		)	—			(32		)
Net Cash Used by Investing Activities	(1,087		)	(732		)	(475		)	1,235			(1,059		)
Cash Flows from Financing Activities
Proceeds from intercompany loans	38			314			883			(1,235		)	—
Payment of dividends to preferred stockholders	—			—			(5		)	—			(5		)
Payments of Intercompany Dividends	—			(4		)	—			4			—
Payment for treasury stock	—			—			(130		)	—			(130		)
Net payments to settle acquired derivatives that include financing elements	(46		)	—			—			—			(46		)
Proceeds from issuance of long-term debt	96			502			3,200			—			3,798
Increase in restricted cash supporting funded letter of credit	—			(1		)	—			—			(1		)
Proceeds from issuance of common stock	—			—			1			—			1
Payment of debt issuance costs	—			(18		)	(34		)	—			(52		)
Payments for short and long-term debt	—			(71		)	(3,762		)	—			(3,833		)
Net Cash Provided/(Used) by Financing Activities	88			722			153			(1,231		)	(268		)
Effect of exchange rate changes on cash and cash equivalents	—			6			—			—			6
Net (Decrease)/Increase in Cash and Cash Equivalents	(148		)	49			(913		)	—			(1,012		)
Cash and Cash Equivalents at Beginning of Period	168			111			2,672			—			2,951
Cash and Cash Equivalents at End of Period	$	20		$	160		$	1,759		$	—		$	1,939


(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 June 30, 2010



(In millions)	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
Operating Revenues
Total operating revenues	$	2,066		$	74		$	—		$	(7	)	$	2,133
Operating Costs and Expenses
Cost of operations	1,283			53			—			(7		)	1,329
Depreciation and amortization	202			4			2			—			208
Selling, general and administrative	72			2			65			—			139
Development costs	—			3			10			—			13
Total operating costs and expenses	1,557			62			77			(7		)	1,689
Gain on sale of assets	—			—			—			—			—
Operating Income/(Loss)	509			12			(77		)	—			444
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries	15			—			332			(347		)	—
Equity in earnings of unconsolidated affiliates	1			10			—			—			11
Other income, net	2			14			3			—			19
Interest expense	(6		)	(9		)	(132		)	—			(147		)
Total other income/(expense)	12			15			203			(347		)	(117		)
Income Before Income Taxes	521			27			126			(347		)	327
Income tax expense/(benefit)	190			12			(85		)	—			117
Net Income	331			15			211			(347		)	210
Less: Net loss attributable to noncontrolling interest	(1		)	—			—			—			(1		)
Net Income attributable to NRG Energy, Inc.	$	332		$	15		$	211		$	(347	)	$	211


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Six Months Ended June 30, 2010



(In millions)	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
Operating Revenues
Total operating revenues	$	4,193		$	169		$	—		$	(14	)	$	4,348
Operating Costs and Expenses
Cost of operations	2,856			119			7			(14		)	2,968
Depreciation and amortization	392			14			4			—			410
Selling, general and administrative	139			5			125			—			269
Development costs	—			6			16			—			22
Total operating costs and expenses	3,387			144			152			(14		)	3,669
Gain on sale of assets	—			—			23			—			23
Operating Income/(Loss)	806			25			(129		)	—			702
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries	22			—			526			(548		)	—
Equity in earnings of unconsolidated affiliates	1			24			—			—			25
Other income, net	3			17			3			—			23
Interest expense	(11		)	(23		)	(266		)	—			(300		)
Total other income/(expense)	15			18			263			(548		)	(252		)
Income Before Income Taxes	821			43			134			(548		)	450
Income tax expense/(benefit)	301			16			(135		)	—			182
Net Income	520			27			269			(548		)	268
Less: Net loss attributable to noncontrolling interest	(1		)	—			—			—			(1		)
Net Income attributable to NRG Energy, Inc.	$	521		$	27		$	269		$	(548	)	$	269


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

December 31, 2010



(In millions)	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
ASSETS
Current Assets
Cash and cash equivalents	$	168		$	111		$	2,672		$	—		$	2,951
Funds deposited by counterparties	408			—			—			—			408
Restricted cash	2			6			—			—			8
Accounts receivable-trade, net	693			38			3			—			734
Inventory	445			8			—			—			453
Derivative instruments valuation	1,964			—			—			—			1,964
Cash collateral paid in support of energy risk management activities	321			2			—			—			323
Prepayments and other current assets	112			60			1,313			(1,189		)	296
Total current assets	4,113			225			3,988			(1,189		)	7,137
Net Property, Plant and Equipment	10,816			1,515			186			—			12,517
Other Assets
Investment in subsidiaries	811			248			22,046			(23,105		)	—
Equity investments in affiliates	47			489			—			—			536
Notes receivable – affiliate and capital leases, less current portion	6,507			380			2,130			(8,633		)	384
Goodwill	1,868			—			—			—			1,868
Intangible assets, net	1,716			58			33			(31		)	1,776
Nuclear decommissioning trust fund	412			—			—			—			412
Derivative instruments valuation	758			—			—			—			758
Restricted cash supporting funded letter of credit facility	—			1,300			—			—			1,300
Other non-current assets	42			22			144			—			208
Total other assets	12,161			2,497			24,353			(31,769		)	7,242
Total Assets	$	27,090		$	4,237		$	28,527		$	(32,958	)	$	26,896
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	1,150		$	223		$	240		$	(1,150	)	$	463
Accounts payable	(2,665		)	229			3,219			—			783
Derivative instruments valuation	1,665			3			17			—			1,685
Deferred income taxes	515			(51		)	(356		)	—			108
Cash collateral received in support of energy risk management activities	408			—			—			—			408
Accrued expenses and other current liabilities	399			34			379			(39		)	773
Total current liabilities	1,472			438			3,499			(1,189		)	4,220
Other Liabilities
Long-term debt and capital leases	1,857			991			14,533			(8,633		)	8,748
Funded letter of credit	—			—			1,300			—			1,300
Nuclear decommissioning reserve	317			—			—			—			317
Nuclear decommissioning trust liability	272			—			—			—			272
Deferred income taxes	1,464			279			246			—			1,989
Derivative instruments valuation	294			34			37			—			365
Out-of-market contracts	248			6			—			(31		)	223
Other non-current liabilities	504			29			609			—			1,142
Total non-current liabilities	4,956			1,339			16,725			(8,664		)	14,356
Total liabilities	6,428			1,777			20,224			(9,853		)	18,576
3.625% Preferred Stock	—			—			248			—			248
Stockholders’ Equity	20,662			2,460			8,055			(23,105		)	8,072
Total Liabilities and Stockholders’ Equity	$	27,090		$	4,237		$	28,527		$	(32,958	)	$	26,896


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2010



(In millions)	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
Cash Flows from Operating Activities
Net income	$	520		$	27		$	269		$	(548	)	$	268
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	10			(11		)	(489		)	481			(9		)
Depreciation and amortization	392			14			4			—			410
Provision for bad debts	22			—			—			—			22
Amortization of nuclear fuel	19			—			—			—			19
Amortization of financing costs and debt discount/premiums	—			3			12			—			15
Amortization of intangibles and out-of market contracts	1			—			—			—			1
Changes in deferred income taxes and liability for uncertain tax benefits	300			2			(123		)	—			179
Changes in nuclear decommissioning trust liability	9			—			—			—			9
Changes in derivatives	(57		)	2			—			—			(55		)
Changes in collateral deposits supporting energy risk management activities	(30		)	—			—			—			(30		)
Cash (used)/provided by changes in other working capital	(456		)	(75		)	307			—			(224		)
Net Cash Provided/(Used) by Operating Activities	730			(38		)	(20		)	(67		)	605
Cash Flows from Investing Activities
Intercompany loans to subsidiaries	(739		)	—			(142		)	881			—
Acquisition of Business	—			(141		)	—			—			(141		)
Investment in subsidiaries	—			1,721			(1,721		)	—			—
Capital expenditures	(145		)	(159		)	(26		)	—			(330		)
Increase in restricted cash, net	—			(11		)	—			—			(11		)
Decrease in notes receivable	—			15			—			—			15
Purchases of emission allowances	(45		)	—			—			—			(45		)
Proceeds from sale of emission allowances	11			—			—			—			11
Investments in nuclear decommissioning trust fund securities	(76		)	—			—			—			(76		)
Proceeds from sales of nuclear decommissioning trust fund securities	67			—			—			—			67
Proceeds from renewable energy grants	84			18			—			—			102
Proceeds from sale of assets	1			—			29			—			30
Other	—			(2		)	(5		)	—			(7		)
Net Cash (Used)/Provided by Investing Activities	(842		)	1,441			(1,865		)	881			(385		)
Cash Flows from Financing Activities
Proceeds from intercompany loans	127			15			739			(881		)	—
Payment of intercompany dividends	(30		)	(37		)	—			67			—
Payment of dividends to preferred stockholders	—			—			(5		)	—			(5		)
Payments for treasury stock	—			—			(50		)	—			(50		)
Installment proceeds from sale of non-controlling interest in subsidiary	—			50			—			—			50
Net receipt from acquired derivatives that include financing elements	27			—			—			—			27
Proceeds from issuance of long-term debt	3			138			—			—			141
Proceeds from issuance of term loan for funded Letter of Credit Facility	—			—			1,300			—			1,300
Increase of restricted cash supporting funded letter of credit	—			(1,300		)	—			—			(1,300		)
Proceeds from issuance of common stock	—			—			2			—			2
Payment of debt issuance costs	(1		)	(7		)	(45		)	—			(53		)
Payments for short and long-term debt	—			(219		)	(240		)	—			(459		)
Net Cash Provided/(Used) by Financing Activities	126			(1,360		)	1,701			(814		)	(347		)
Effect of exchange rate changes on cash and cash equivalents	—			(9		)	—			—			(9		)
Net (Decrease)/Increase in Cash and Cash Equivalents	14			34			(184		)	—			(136		)
Cash and Cash Equivalents at Beginning of Period	20			120			2,164			—			2,304
Cash and Cash Equivalents at End of Period	$	34		$	154		$	1,980		$	—		$	2,168

(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 six months ended June 30, 2011, and 2010. Also refer to NRG's Annual Report on Form 10-K for the year ended December 31, 2010, or 2010 Form 10-K, which includes detailed discussions of various items impacting the Company's business, results of operations and financial condition, including: Introduction and Overview section which provides a description of NRG's business segments; Strategy section; Business Environment section, including how regulation, weather, and other factors affect NRG's business; and Critical Accounting Policies and Estimates section.

The discussion and analysis below has been organized as follows:


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


•	Results of operations;


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


•	Known trends that may affect NRG’s results of operations and financial condition in the future.

Executive Summary

Introduction and Overview

As of June 30, 2011, NRG had a total global generation portfolio of 199 active operating fossil fuel and nuclear generation units, at 46 power generation plants, with an aggregate generation capacity of approximately 24,995 MW, and approximately 1,015 MW under construction which includes partner interests of 218 MW. In addition to its fossil fuel plant ownership, NRG has ownership interests in operating renewable facilities with an aggregate generation capacity of 470 MW, consisting of four wind farms representing an aggregate generation capacity of 450 MW, and 20 MW from a solar facility. Within the United States, NRG has large and diversified power generation portfolios in terms of geography, fuel-type and dispatch levels, with approximately 23,990 MW of fossil fuel and nuclear generation capacity in 191 active generating units at 44 plants. The Company's power generation facilities are most heavily concentrated in Texas (approximately 11,150 MW, including 450 MW from four wind farms), the Northeast (approximately 6,915 MW), South Central (approximately 4,125 MW), and West (approximately 2,155 MW, including 20 MW from a solar facility) regions of the United States. Through certain foreign subsidiaries, NRG has investments in power generation projects located in Australia and Germany with approximately 1,005 MW of generation capacity. In addition, NRG has approximately 115 MW of additional generation capacity from the Company's thermal assets, as well as a district energy business that has a steam and chilled water capacity of approximately 1,140 megawatts thermal equivalent, or MWt.

NRG's principal domestic power plants consist of a mix of natural gas-, coal-, oil-fired, nuclear and renewable facilities, representing approximately 47%, 30%, 16%, 5% and 2% of the Company's total domestic generation capacity, respectively. In addition, 7% of NRG's domestic generating facilities have dual or multiple fuel capacity.

NRG's domestic generation facilities consist of intermittent, baseload, intermediate and peaking power generation facilities. The sale of capacity and power from baseload generation facilities accounts for the majority of the Company's revenues. In addition, NRG's generation portfolio provides the Company with opportunities to capture additional revenues by selling power during periods of peak demand, offering capacity or similar products to retail electric providers and others, and providing ancillary services to support system reliability.

Reliant Energy and Green Mountain Energy arrange for the transmission and delivery of electricity to customers, bill customers, collect payments for electricity sold and maintain call centers to provide customer service. Based on metered locations, as of June 30, 2011, Reliant Energy and Green Mountain Energy combined to serve approximately 1.9 million residential, small business, commercial and industrial customers.

Furthermore, NRG is focused on the development and investment in energy-related new businesses and new technologies where the benefits of such investments represent significant commercial opportunities and create a comparative advantage for the Company. These investments include low or no GHG emitting energy generating sources, such as wind, solar thermal, solar photovoltaic, biomass, gasification, the retrofit of post-combustion carbon capture technologies, and fueling infrastructure for electric vehicle ecosystems.

NRG's Business Strategy

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

The Company's core business is focused on: (i) excellence in safety and operating performance of its existing operating assets, (ii) serving the energy needs of end-use residential, commercial and industrial customers in the Company's core markets, (iii) optimal hedging of baseload generation and retail load operations, while retaining optionality on the Company's gas fleet, (iv) repowering of power generation assets at existing sites and reducing environmental impacts, (v) pursuing selective acquisitions, joint ventures, divestitures and investments, and (vi) 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.

In addition, the Company believes that it is well-positioned to capture the opportunities arising out of a long-term societal trend towards sustainability as a result of technological developments and new product offerings in “green” energy. The Company's initiatives in this area of future growth are focused on: (i) renewables, with a concentration in solar and wind generation and development; (ii) fast start, high efficiency gas-fired capacity in the Company's core regions; (iii) electric vehicle ecosystems; and (iv) smart grid services. The Company's advances in each of these areas are driven by select acquisitions, joint ventures, and investments that are more fully described in the Company's 2010 Form 10-K and this Form 10-Q.

Environmental Matters

Environmental Regulatory Landscape

A number of regulations that could significantly impact the power generation industry are in development or under review by the U.S. EPA as of June 30, 2011: CATR, NSPS for GHGs, MACT, NAAQS revisions, coal combustion byproducts, and once-through cooling. While most of these regulations have been under consideration for some time, they are expected to gain clarity in 2011 and 2012. The timing and stringency of these regulations will provide a framework for the retrofit of existing fossil plants and deployment of new, cleaner technologies in the next decade. The Company has included capital to meet anticipated CATR, Mercury and Air Toxics Standards, and the installation of BTA under the 316(b) Rule in the current estimated environmental capital expenditures. The Company cannot predict the impact of changes in these proposed rules nor future regulations and could face additional investments over time. However, NRG believes it is positioned to meet more stringent requirements through its planned capital expenditures, existing controls, and the use of Powder River Basin coal.

The U.S. EPA released CSAPR on July 7, 2011. CSAPR will replace CAIR and is designed to bring 27 states and Washington, D.C. into attainment with PM 2.5 and ozone NAAQS, reducing SO₂ and NO_x emissions from power plants. Proposed implementation will be through cap and trade programs starting in 2012 for Group 1 SO₂, Group 2 SO₂, Annual NO_x, and Ozone Season NO_x. In 2014, the SO₂ cap would be further reduced in Group 1 states. Under CSAPR, use of discounted Acid Rain SO₂ and CAIR NO_x allowances will be discontinued and replaced with completely distinct allowance programs. Acid Rain allowances will still be required on a 1:1 basis under the Acid Rain Program. NRG owns or has minority interests in plants in six states that are covered by the rule.



State	Group 1 SO₂	Group 2 SO₂	Annual NO_x	Ozone NO_x
IL	X		X	X
LA				X
MD	X		X	X
NY	X		X	X
PA	X		X	X
TX		X	X	X

The final rule differed from the proposed rule in that Texas was added into the Group 2 SO₂ and Annual NO_x programs, Delaware and Connecticut are no longer under the rule and Louisiana is limited to ozone season NO_x. In general, with the exception of Pennsylvania Annual and Ozone Season NO_x, these states saw tightening of the state budget between the proposed and final rules. Despite already low emission rates, NRG's allowance allocations are less than 2010 emissions.

NRG is reviewing the recent rule and developing an integrated strategy based on enhancing the performance of existing controls, fuel adjustments, other operational changes, and allowance acquisition. While it is still early in the review process, we do not expect any incremental environmental capital investment to be material. In the second half of 2011, this rule will result in an impairment charge ranging from $150 million to $200 million on the Company's excess Acid Rain Program SO₂ emission allowances, which are recorded as an intangible asset on the Company's balance sheet.

On March 16, 2011, the U.S. EPA released the proposed Mercury and Air Toxics Standards to control emissions of hazardous air pollutants. NRG's existing and currently planned environmental capital expenditures are consistent with reductions required per the proposed rule. Additional investments for compliance cannot be determined until the rule is final.

In July 2004, the U.S. EPA published rules governing cooling water intake structures at existing power facilities commonly referred to as the 316(b) Rule. As a result of a decision by the U.S. Court of Appeals for the Second Circuit, the U.S. EPA suspended the rule in July 2007 while preparing a revised version. On March 28, 2011, the U.S. EPA released the proposed 316(b) Rule. States such as California and New York moved ahead with their own more stringent requirements for once-through cooled units, which are expected to satisfy the requirements of the proposed 316(b) Rule. On July 20, 2011, the New York State Department of Environmental Conservation, or NYDEC, announced the State's final policy on cooling water intake structures, confirming the Company's current capital expenditure in that state. NRG expects to comply with these requirements with a mix of intake and operational modifications.

The California Air Resources Board released a series of draft changes to the rules implementing the state's GHG cap and trade program under AB 32. Among those changes is a delay of the program start from 2012 to 2013.

Regulatory Matters

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

California — On March 17, 2011, FERC issued an order on CAISO's proposal to replace its interim backstop Capacity Procurement Mechanism, or CPM, with a permanent version. The proposed CPM addresses capacity payments for generating units not contracted to fulfill California's Resource Adequacy requirements, but nevertheless needed for reliability. FERC accepted CAISO's proposal effective April 1, 2011, subject to refund and convened a technical conference to expeditiously explore issues related to the pricing of the CPM. Market participants are discussing resolution of these matters.

New England — On April 13, 2011, FERC issued an order addressing proposed amendments submitted by ISO-NE to its Forward Capacity Market, or FCM, design, as well as two pending complaints. Among other market revisions, FERC's order extends the price floor for “at least” the fifth (2014/2015) and sixth (2015/2016) Forward Capacity Auctions in order to address the effect of historical out-of-market capacity. Requests for rehearing have been submitted by numerous parties and compliance filings are pending and being contested.

New York — On November 30, 2010, the NYISO filed at FERC its proposed installed capacity demand curves for 2011/2012, 2012/2013, and 2013/2014. The demand curves are a critical determinant of capacity market prices. The Company and other market participants protested the NYISO's filing, and on January 28, 2011, FERC found in favor of generators on a number of issues principally related to determining the cost of new entry and the resulting adjustments to the demand curves should positively affect capacity clearing prices. On May 19, 2011, FERC granted rehearing to remove property taxes from the cost of new entry of new in-city generation and denied other requests for rehearing. A coalition of New York in-city generators, including the Company, is seeking rehearing of the May 19, 2011, order. In addition, on June 3, 2011, as amended on June 15, 2011, the same coalition of New York in-city generators filed a complaint with FERC seeking additional transparency into: (i) whether the NYISO was correctly evaluating whether new entrants into the capacity markets should be subject to mitigation and, if so, (ii) whether the NYISO was appropriately setting the level of any mitigation. On June 29, 2011, the NYISO released its July spot capacity auction clearing prices for New York City, which significantly decreased over June clearing prices. The apparent cause of this decrease was a decision by the NYISO to allow a new entrant to bid into the July spot capacity auction, either without mitigation or without proper mitigation. Additionally, another new entrant has since indicated that it also received a mitigation exemption from NYISO and that it intends to begin participating in the NYISO capacity market starting with the May 2012 capability period. The addition of this second new entrant may further affect capacity clearing prices in New York. On July 10, 2011, in response to the July spot auction capacity clearing prices, two generators filed a second complaint alleging that the NYISO had improperly exempted both new entrants from mitigation, and requested that FERC immediately direct the NYISO to apply its offer-floor market mitigation rules to both new entrants, to resettle the July capacity spot auction, and other relief. Certain of NRG's subsidiaries filed a motion to intervene at FERC in support of applying offer-floor mitigation to the new entrants. Both complaints are pending before FERC.

PJM — On April 12, 2011, FERC issued an order addressing a complaint filed by PJM Power Providers Group seeking to require PJM to address the potential adverse impacts of out-of-market generation, as well as PJM's subsequent submission seeking revisions to the capacity market design, in particular the Minimum Offer Price Rule, or MOPR. In its order, FERC generally strengthened the MOPR and the protections against market price distortion from out-of-market generation. Requests for rehearing have been submitted by numerous parties and compliance filings are pending and being contested. FERC convened a technical conference on July 28, 2011, to further explore issues associated with self-supply and out-of-market generation.

South Central — On April 25, 2011, Entergy Corporation, or Entergy, announced that it will pursue joining the Midwest Independent System Operator regional transmission organization, or MISO, with a current target date for joining of December 2013. Entergy's proposal is subject to approval from the regulatory commissions of the states of Arkansas, Louisiana, Mississippi, and Texas, as well as the City of New Orleans. The Company's South Central region is dependent upon Entergy's transmission system to conduct its business, and thus would necessarily move with Entergy into MISO. This development is not expected to materially impact the Company's ability to serve its customers in the region, and we are continuing to analyze the impact of the possible changes in transmission access and market design.

Texas — On February 2, 2011, ERCOT experienced unusually cold temperatures that resulted in a power emergency, rotating blackouts, and a new all-time winter peak of 56,334 MW (on February 10, 2011, ERCOT again set a new winter peak of 57,315 MW). Several regulators are reviewing the circumstances surrounding the cold snap, and have issued requests for information to market participants, including NRG. During the load shed event, the Company satisfied its load responsibilities and wholesale obligations, and complied with ERCOT's instructions.

Nuclear Regulatory Commission, or NRC, Task Force Report — On July 12, 2011, the NRC Near-Term Task Force, or the Task Force, issued its report, which reviewed nuclear processes and regulations in light of the accident at the Fukushima Daiichi Nuclear Power Station in Japan. The Task Force concluded that U.S. nuclear plants are operating safely and did not identify changes to the existing nuclear licensing process nor recommend fundamental changes to spent nuclear fuel storage. The Task Force report made recommendations in three key areas: the NRC's regulatory framework, specific plant design requirements, and emergency preparedness and actions. STPNOC expects the report to be the first step in a longer-term review that the NRC will conduct, along with seeking broad stakeholder input. STPNOC continues to apply lessons learned and work with regulators and industry organizations on appropriate assessments and actions. Until further actions are taken by the NRC, the Company cannot predict the impact of the recommendations in the NRC Task Force report, and could face additional investments at STP Units 1 & 2.

Changes in Accounting Standards

None.

Consolidated Results of Operations

The following table provides selected financial information for the Company:



	Three months ended June 30,								Six months ended June 30,
(In millions except otherwise noted)	2011			2010			Change %		2011			2010			Change %
Operating Revenues
Energy revenue^(a)	$	529		$	682		(22	)%	$	1,127		$	1,379		(18	)%
Capacity revenue ^(a)	183			204			(10	)	368			413			(11	)
Retail revenue	1,464			1,341			9		2,644			2,586			2
Mark-to-market for economic hedging activities	69			(100		)	169		68			(63		)	208
Contract amortization	(44		)	(52		)	15		(91		)	(114		)	20
Thermal revenue	33			29			14		73			66			11
Other revenues ^(b)	44			29			52		84			81			4
Total operating revenues	2,278			2,133			7		4,273			4,348			(2	)
Operating Costs and Expenses
Generation cost of sales^(a)	594			468			27		1,132			938			21
Retail cost of sales^(a)	683			705			(3	)	1,292			1,432			(10	)
Mark-to-market for economic hedging activities	26			(145		)	118		(108		)	(38		)	(184	)
Contract and emissions credit amortization ^(c)	12			3			300		21			4			425
Thermal cost of sales	13			14			(7	)	32			30			7
Other cost of operations	280			284			(1	)	563			602			(6	)
Total cost of operations	1,608			1,329			21		2,932			2,968			(1	)
Depreciation and amortization	222			208			7		427			410			4
Selling, general and administrative	167			139			20		310			269			15
Development costs	12			13			(8	)	21			22			(5	)
Total operating costs and expenses	2,009			1,689			19		3,690			3,669			1
Gain on sale of assets	—			—			N/A		—			23			(100	)
Operating Income	269			444			(39	)	583			702			(17	)
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates	12			11			9		10			25			(60	)
Impairment charge on investment	(11		)	—			N/A		(492		)	—			N/A
Other income, net	3			19			(84	)	8			23			(65	)
Loss on debt extinguishment	(115		)	—			N/A		(143		)	—			N/A
Interest expense	(167		)	(147		)	14		(340		)	(300		)	13
Total other expense	(278		)	(117		)	138		(957		)	(252		)	280
(Loss)/Income before income tax expense	(9		)	327			(103	)	(374		)	450			(183	)
Income tax (benefit)/expense	(630		)	117			(638	)	(735		)	182			(504	)
Net Income	621			210			196		361			268			35
Less: Net loss attributable to noncontrolling interest	—			(1		)	(100	)	—			(1		)	(100	)
Net Income Attributable to NRG Energy, Inc.	$	621		$	211		194		$	361		$	269		34
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)	4.31			4.09			5	%	4.21			4.69			(10	)%

(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 June 30, 2011 and 2010

(Loss)/Income before income tax expense — The pre-tax loss of $9 million for the three months ended June 30, 2011, compared to income of $327 million for the three months ended June 30, 2010, primarily reflects a $167 million decrease in generation gross margin, and a $115 million loss on the extinguishment of the 2016 Senior Notes.

Net income — The increase in net income of $410 million primarily reflects the drivers discussed above as well as the impact of the resolution of the federal tax audit in June 2011 and the related recognition of previously uncertain tax benefits which is the primary reason for the tax benefit for the three months ended June 30, 2011 of $630 million, compared with income tax expense of $117 million in the comparable period.

Wholesale Power Generation gross margin

The following is a discussion of gross margin for NRG's wholesale power generation regions, adjusted to eliminate intersegment activity, primarily with Reliant Energy and Green Mountain Energy.



	Three months ended June 30, 2011
(In millions except otherwise noted)	Texas			Northeast			South Central			West			Other			Total Wholesale Power Generation			Eliminations			ConsolidatedTotal
Energy revenue	$	680		$	145		$	118		$	6		$	16		$	965		$	(436	)	$	529
Capacity revenue	5			75			61			27			18			186			(3		)	183
Thermal revenue	—			—			—			—			33			33			—			33
Other revenue	21			14			5			2			7			49			(5		)	44
Generation revenue	706			234			184			35			74			1,233			(444		)	789
Generation cost of sales	(318		)	(128		)	(114		)	(3		)	(31		)	(594		)	—			(594		)
Thermal cost of sales	—			—			—			—			(13		)	(13		)	—			(13		)
Generation cost of sales	(318		)	(128		)	(114		)	(3		)	(44		)	(607		)	—			(607		)
Generation gross margin	$	388		$	106		$	70		$	32		$	30		$	626		$	(444	)	$	182

Business Metrics
MWh sold (in thousands)	12,906			2,344			3,628			49
MWh generated (in thousands)	12,333			1,879			3,662			49
Average on-peak market power prices ($/MWh)	$	41.07		$	54.09		$	38.75		$	34.88



	Three months ended June 30, 2010
(In millions except otherwise noted)	Texas			Northeast			South Central			West			Other			Total Wholesale Power Generation			Eliminations			Consolidated Total
Energy revenue	$	734		$	159		$	88		$	3		$	10		$	994		$	(312	)	$	682
Capacity revenue	5			100			58			27			17			207			(3		)	204
Thermal revenue	—			—			—			—			29			29			—			29
Other revenue	33			8			4			1			(1		)	45			(16		)	29
Generation revenue	772			267			150			31			55			1,275			(331		)	944
Generation cost of sales	(263		)	(93		)	(89		)	(1		)	(22		)	(468		)	—			(468		)
Thermal cost of sales	—			—			—			—			(14		)	(14		)	—			(14		)
Generation cost of sales	(263		)	(93		)	(89		)	(1		)	(36		)	(482		)	—			(482		)
Generation gross margin	$	509		$	174		$	61		$	30		$	19		$	793		$	(331	)	$	462

Business Metrics
MWh sold (in thousands)	11,963			1,980			3,221			28
MWh generated (in thousands)	11,444			1,688			2,366			28
Average on-peak market power prices ($/MWh)	$	39.30		$	54.05		$	38.96		$	35.40

	Three months ended June 30,
Weather Metrics	Texas			Northeast			South Central			West
2011
CDDs ^(a)	1,183			164			653			68
HDDs ^(a)	63			723			247			660
2010
CDDs	1,004			215			689			75
HDDs	79			594			182			674
30 year average
CDDs	854			105			458			150
HDDs	83			837			299			546

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

Generation gross margin — decreased by $280 million, on a consolidated basis, during the three months ended June 30, 2011, compared to the same period in 2010. Including intercompany sales, generation gross margin decreased by $167 million, due to:



Decrease in Texas region	$	(121	)
Decrease in Northeast region	(68		)
Increase in South Central region	9
Other	13
	$	(167	)

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



Lower energy revenue due to a 14% decrease in realized prices, which reflects lower hedged prices in 2011	$	(111	)
Higher coal costs from a 9% increase in prices related to an increase in fuel surcharges	(14		)
Higher natural gas costs from an 8% increase in average prices related to higher market prices	(7		)
Favorable impact from a 4% increase in coal generation driven by higher economic dispatch	13
Favorable impact from a 53% increase in wind generation primarily due to the South Trent acquisition in 2010.	8
Favorable impact from a 35% increase in natural gas generation driven by warmer weather compared to 2010	6
Higher purchased energy costs from increased obligations when baseload plants are unavailable	(10		)
Other	(6		)
	$	(121	)

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



Lower energy revenue due to a 38% decrease in realized prices, which reflects lower hedged prices in 2011	$	(53	)
Higher energy revenue due to an 11% increase in generation	7
Lower capacity revenue due to higher forced outage rates, offset by an increase in realized prices of 3%	(19		)
Lower capacity revenue due to an 80% decrease in LFRM prices and a 40% decrease in LFRM capacity sold	(9		)
Lower oil costs due to a 93% decrease in generation at plants in New England	5
Higher coal costs due to a 13% increase in coal generation and 9% higher average prices, which reflects higher transportation costs	(9		)
Increase in unrealized trading revenue	8
Other	2
	$	(68	)

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



Higher merchant revenue related to a 69% increase in average realized prices, which reflects higher margin on purchases for resale	$	15
Higher merchant revenue due to a 39% increase in MWh sold, primarily related to two additional Cottonwood units	6
Higher contract revenue from new contracts with two regional municipalities	9
Higher capacity revenue due primarily to contributions from the Rockford Plants in the PJM market	4
Higher natural gas costs related to the addition of the Cottonwood facility to the regional portfolio	(21		)
Higher coal costs due to an 8% increase in generation and an increase in prices driven by a higher transportation cost	(8		)
Other	4
	$	9

Retail gross margin

The Company's retail gross margin, which reflects retail operating revenues less retail cost of sales, include the results of NRG's Reliant Energy business segment, as well as the results of Green Mountain Energy which is included in NRG's Corporate business segment.



	Three months ended June 30, 2011
(In millions)	Reliant Energy		Green Mountain^(a)		Eliminations			Consolidated Total
Retail operating revenues	$	1,299	$	167	$	(2	)	$	1,464
Retail cost of sales	1,005		119		(441		)	683
(a) Green Mountain Energy was acquired in November 2010.

			Three months ended June 30, 2010
(In millions)			Reliant Energy		Eliminations			Consolidated Total
Retail operating revenues			$	1,341	$	—		$	1,341
Retail cost of sales			1,033		(328		)	705

Reliant Energy

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

Selected Income Statement Data



	Three months ended June 30,
(In millions except otherwise noted)	2011		2010
Operating Revenues
Mass revenues	$	778	$	808
Commercial and Industrial revenues	488		502
Supply management revenues	33		31
Retail operating revenues ^(a)	1,299		1,341
Retail cost of sales ^(b)	1,005		1,033
Retail gross margin	$	294	$	308

Business Metrics
Electricity sales volume — GWh
Mass	6,134		5,732
Commercial and Industrial ^(a)	6,674		6,683
Average retail customers count (in thousands, metered locations)
Mass	1,471		1,503
Commercial and Industrial^(a)	60		63
Retail customers count (in thousands, metered locations)
Mass	1,477		1,488
Commercial and Industrial^(a)	61		63

Weather Metrics
CDDs ^(c)	1,315		1,163
HDDs^(c)	27		26


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


(b)	Includes intercompany purchases from the Texas region of $402 million and $328 million, respectively.


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


•	Retail gross margin — Reliant Energy's gross margin decreased $14 million for the three months ended June 30, 2011, compared to the same period in 2010, driven by:



Favorable weather impact driven by warmer weather in 2011 yielding 9% higher overall Mass customer usage, partially offset by 11% lower gross margin per MWh on the incremental weather volumes	$	24
2% fewer Mass customers primarily driven by 0.1% net attrition between July 2010 and June 2011	(10		)
Decrease in Mass revenue rates due to lower pricing on acquisitions and renewals consistent with competitive offers	(68		)
Decrease in supply costs due to 4% lower hedged prices	53
Estimated favorable impact in 2010 as compared to 2011 from the termination of out-of-market supply contracts in conjunction with 2009 CSRA unwind	(18		)
Other	5
	$	(14	)


•	Trends — Competition and lower unit margins on acquisitions and renewals could drive lower revenues and gross margin in the future. Mass customer counts increased by 6,000 since March 31, 2011, indicating a stabilization of customer attrition. Favorable weather in both periods resulted in higher customer usage of 20% in 2011 and 8% in 2010 when compared to ten-year normal weather.

Green Mountain Energy

The following is a discussion of retail gross margin for Green Mountain Energy for the three months ended June 30, 2011:



Retail operating revenues	$	167
Retail cost of sales ^(a)	119
Retail gross margin	$	48
(a) Includes intercompany purchases of $39 million

•

Retail gross margin — Green Mountain Energy's gross margin of $48 million for the three months ended June 30, 2011, reflects increased customer usage due to favorable impact of warmer than normal weather, as compared to the 30-year CDD average. Revenues were generated 62% and 38% from residential and commercial customers, respectively. Total metered customer counts were approximately 0.4 million at period end and increased approximately 6%, or 22,000, from March 31, 2011.

Mark-to-market for Economic Hedging Activities

Mark-to-market for economic hedging activities includes asset-backed hedges that did not qualify for cash flow hedge accounting and ineffectiveness on cash flow hedges. Total net mark-to-market results decreased by $2 million during the three months ended June 30, 2011, compared to the same period in 2010.

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



	Three months ended June 30, 2011
	Reliant Energy			Texas			Northeast			South Central			West			Thermal		Corporate ^(a)			Elimination^(b)			Total
	(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(1	)	$	(10	)	$	3		$	7		$	(1	)	$	—	$	—		$	12		$	10
Net unrealized gains/(losses) on open positions related to economic hedges	5			126			9			(8		)	4			—		—			(77		)	59
Total mark-to-market gains/(losses) in operating revenues	$	4		$	116		$	12		$	(1	)	$	3		$	—	$	—		$	(65	)	$	69
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	31		$	1		$	(2	)	$	—		$	—		$	—	$	(4	)	$	(12	)	$	14
Reversal of loss positions acquired as part of the Reliant Energy acquisition as of May 1, 2009	19			—			—			—			—			—		—			—			19
Reversal of loss positions acquired as part of the Green Mountain Energy acquisition as of November 5, 2010	—			—			—			—			—			—		11			—			11
Net unrealized (losses)/gains on open positions related to economic hedges	(137		)	6			1			3			—			—		(20		)	77			(70		)
Total mark-to-market (losses)/gains in operating costs and expenses	$	(87	)	$	7		$	(1	)	$	3		$	—		$	—	$	(13	)	$	65		$	(26	)

(a) Corporate segment consists of Green Mountain Energy activity.

(b) Represents the elimination of the intercompany activity between the Texas or Northeast regions with Green Mountain Energy or Reliant Energy.



	Three months ended June 30, 2010
	Reliant Energy			Texas			Northeast			South Central			West		Thermal			Corporate		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	$	—		$	(16	)	$	(34	)	$	1		$	—	$	(1	)	$	—	$	2		$	(48	)
Net unrealized (losses)/gains on open positions related to economic hedges	—			(66		)	(28		)	(4		)	1		—			—		45			(52		)
Total mark-to-market (losses)/gains in operating revenues	$	—		$	(82	)	$	(62	)	$	(3	)	$	1	$	(1	)	$	—	$	47		$	(100	)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(17	)	$	8		$	4		$	4		$	—	$	—		$	—	$	(2	)	$	(3	)
Reversal of loss positions acquired as part of the Reliant Energy acquisition as of May 1, 2009	60			—			—			—			—		—			—		—			60
Net unrealized gains/(losses) on open positions related to economic hedges	120			8			—			5			—		—			—		(45		)	88
Total mark-to-market gains/(losses) in operating costs and expenses	$	163		$	16		$	4		$	9		$	—	$	—		$	—	$	(47	)	$	145


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

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

For the three months ended June 30, 2011, the net losses on open positions were due to a decrease in forward power and gas prices. Reliant Energy's $19 million gain from the roll-off of acquired derivatives consists of loss positions that were acquired as of May 1, 2009, and valued using forward prices on that date. Green Mountain Energy's $11 million gain from the roll-off of acquired derivatives consists of loss positions that were acquired as of November 5, 2010, and valued using forward prices on that date. The roll-off amounts were offset by realized losses at the settled prices and higher costs of physical power which are reflected in operating costs and expenses during the same period.

For the three months ended June 30, 2010, the net gains on open positions were due to an increase in forward power and gas prices. Reliant Energy's $60 million gain from the roll-off of acquired derivatives consists of loss positions that were acquired as of May 1, 2009, and valued using forward prices on that date. The roll-off amounts were offset by realized losses at the settled prices and higher costs of physical power which are reflected in revenues and cost of operations 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 June 30, 2011, and 2010. The realized financial and physical trading results are included in operating revenue and the unrealized financial and physical trading results are included in other revenue. The Company's trading activities are subject to limits within the Company's Risk Management Policy.



	Three months ended June 30,
(In millions)	2011		2010
Trading gains/(losses)
Realized	$	18	$	(13	)
Unrealized	22		17
Total trading gains	$	40	$	4

Contract Amortization Revenue

Contract amortization represents the roll-off of in-market customer contracts valued under purchase accounting and the decrease of $8 million as compared to the prior period in 2010 related primarily to lower contract amortization for Reliant Energy of $20 million, offset by higher contract amortization of $9 million for Green Mountain Energy.

Contract and Emissions Credit Amortization

The increase in contract and emissions credit amortization primarily reflects lower contract amortization, which is an offset to expense, due to the roll-off of energy supply contracts valued in purchase accounting for Reliant Energy.

Other Operating Costs



(In millions)	Reliant Energy	Texas	Northeast	South Central	West	Thermal	Other	Total
Three months ended June 30, 2011	$48	$129	$48	$24	$18	$10	$3	$280
Three months ended June 30, 2010	$49	$127	$54	$35	$15	$9	$(5)	$284

Other operating costs decreased by $4 million for the three months ended June 30, 2011, compared to the same period in 2010, due to:



Decrease in Northeast region operations and maintenance expense	$	(15	)
Decrease in South Central region operations and maintenance expense	(12		)
Other increases in operations and maintenance expense	14
Increase in property tax expense	8
Other	1
	$	(4	)


◦	Northeast operations and maintenance — decreased due to a decrease in operational labor from headcount reductions, a decrease in normal and major maintenance due to the timing of outages at the region's coal plants and also as the prior year reflected asset write-offs of $5 million.


◦	South Central operations and maintenance — decreased as a result of less maintenance work during planned outages at the region's baseload plants as compared to the same period in 2010.


◦	Other operations and maintenance — increased due to the acquisition of Green Mountain Energy, as well as due to the timing of planned outages at various plants.


◦	Property tax expense - increased primarily due to less New York Empire Zone tax credits in 2011 as compared to 2010.

Depreciation and Amortization Expense

Depreciation and amortization expense increased by $14 million for the three months ended June 30, 2011, compared to the same period in 2010 due primarily to the acquisitions of Cottonwood, Green Mountain Energy, and Northwind Phoenix in 2010.

Selling, General and Administrative Expenses

Selling, general and administrative expenses increased by $28 million for the three months ended June 30, 2011, compared to the same period in 2010 due primarily to the acquisition of Green Mountain Energy in November 2010. Green Mountain Energy's selling, general and administrative costs were $19 million for the three months ended June 30, 2011. In addition, selling, general and administrative expenses increased due to increased marketing costs associated with additional advertising campaigns and sponsorship arrangements. This increase was offset in part by a decrease in bad debt expense of $5 million at Reliant Energy due to improved customer payment behavior and decreased revenues.

Equity in Earnings of Unconsolidated Affiliates

NRG's equity earnings from unconsolidated affiliates increased by $1 million for the three months ended June 30, 2011, compared to the same period in 2010. The increase is due to higher earnings of $4 million from Saguaro and $4 million from GenConn, as the Devon peaking facility commenced commercial operations in June 2010, and due to an increase of $2 million in the fair value of Sherbino's forward gas contract, offset by lower equity earnings of $9 million from Gladstone.

Impairment Charge on Investment

As discussed in more detail in Note 5, Nuclear Innovation North America LLC Developments, Including Impairment Charge, of this Form 10-Q, 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 equal to the balance of its investment in NINA. In concurrence with a substantial reduction in NINA's project workforce, and to support NINA's reduced scope of work, NRG contributed an additional $11 million into NINA during the three months ended June 30, 2011, which NRG also expensed as an impairment charge.

Other Income, net

Other income, net, decreased by $16 million for the three months ended June 30, 2011, compared to the same period in 2010, which relates primarily to foreign exchange gains recognized in the prior period.

Loss on Debt Extinguishment

A loss on the extinguishment of the 2016 Senior Notes of $115 million was recorded in the three months ended June 30, 2011, which primarily consisted of the premiums paid on the redemption of the 2016 Senior Notes and the write-off of previously deferred financing costs.

Interest Expense

NRG's interest expense increased by $20 million for the three months ended June 30, 2011, compared to the same period in 2010 due to the following:



Increase/(decrease) in interest expense	(In millions)
Increase for 2020 Senior Notes issued in August 2010	$	22
Increase for 2018 Senior Notes issued in January 2011	22
Increase for 2019 and 2021 Senior Notes issued in May 2011	16
Increase for project financings	3
Increase for tax-exempt bonds	3
Decrease for capitalized interest	(10		)
Decrease for 2014 Senior Notes redeemed in January and February 2011	(19		)
Decrease for 2016 Senior Notes redeemed in May and June 2011	(14		)
Other	(3		)
Total	$	20

Income Tax (Benefit)/Expense

For the three months ended June 30, 2011, NRG recorded an income tax benefit of $630 million on a pre-tax loss of $9 million. For the same period in 2010, NRG recorded income tax expense of $117 million on pre-tax income of $327 million. The effective tax rate was 7,000.0% and 35.8% for the three months ended June 30, 2011, and 2010, respectively.

For the three months ended June 30, 2011, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to a benefit of $612 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 in June 2011 and that were mainly composed of net operating losses of $536 million which had been classified as capital loss carryforwards for financial statement purposes. In addition, a valuation allowance net decrease of $40 million increased the effective tax rate. For the three months ended June 30, 2010, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to state and local income taxes, as well as recording federal and state tax expense and interest for uncertain tax benefits.

Management’s discussion of the results of operations for the six months ended June 30, 2011 and 2010

(Loss)/Income before income tax expense — The pre-tax loss of $374 million for the six months ended June 30, 2011, compared to income of $450 million for the six months ended June 30, 2010, reflects a $492 million loss on the impairment of NRG's investment in NINA and a $143 million loss on the extinguishment of the 2014 Senior Notes and the 2016 Senior Notes. In addition, generation gross margin was lower by $308 million, offset in part by a net increase in mark-to-market activities, with a net gain of $176 million for the six months ended June 30, 2011 as compared to a net loss of $25 million for the same period in 2010.

Net income - The increase in net income of $93 million primarily reflects the drivers discussed above, offset by a tax benefit of $735 million for the six months ended June 30, 2011, which primarily reflects the impact of the resolution of the federal tax audit in June 2011, compared to income tax expense of $182 million in the prior period.

Wholesale Power Generation gross margin

The following is a discussion of gross margin for NRG's wholesale power generation regions, adjusted to eliminate intersegment activity primarily with Reliant Energy and Green Mountain Energy.



	Six months ended June 30, 2011
(In millions except otherwise noted)	Texas			Northeast			South Central			West			Other			Total Wholesale Power Generation			Eliminations			ConsolidatedTotal
Energy revenue	$	1,278		$	296		$	230		$	12		$	30		$	1,846		$	(719	)	$	1,127
Capacity revenue	10			149			122			56			36			373			(5		)	368
Thermal revenue	—			—			—			—			73			73			—			73
Other revenue	55			13			8			5			11			92			(8		)	84
Generation revenue	1,343			458			360			73			150			2,384			(732		)	1,652
Generation cost of sales	(560		)	(273		)	(235		)	(5		)	(59		)	(1,132		)	—			(1,132		)
Thermal cost of sales	—			—			—			—			(32		)	(32		)	—			(32		)
Generation cost of sales	(560		)	(273		)	(235		)	(5		)	(91		)	(1,164		)	—			(1,164		)
Generation gross margin	$	783		$	185		$	125		$	68		$	59		$	1,220		$	(732	)	$	488

Business Metrics
MWh sold (in thousands)	24,263			4,936			7,474			83
MWh generated (in thousands)	22,993			3,911			7,659			83
Average on-peak market power prices ($/MWh)	$	45.77		$	56.00		$	36.99		$	35.12



	Six months ended June 30, 2010
(In millions except otherwise noted)	Texas			Northeast			South Central			West			Other			Total Wholesale Power Generation			Eliminations			Consolidated Total
Energy revenue	$	1,371		$	313		$	182		$	11		$	23		$	1,900		$	(521	)	$	1,379
Capacity revenue	12			204			115			53			36			420			(7		)	413
Thermal revenue	—			—			—			—			66			66			—			66
Other revenue	72			23			9			2			4			110			(29		)	81
Generation revenues	1,455			540			306			66			129			2,496			(557		)	1,939
Generation cost of sales	(494		)	(191		)	(197		)	(6		)	(50		)	(938		)	—			(938		)
Thermal cost of sales	—			—			—			—			(30		)	(30		)	—			(30		)
Generation cost of sales	(494		)	(191		)	(197		)	(6		)	(80		)	(968		)	—			(968		)
Generation gross margin	$	961		$	349		$	109		$	60		$	49		$	1,528		$	(557	)	$	971

Business Metrics
MWh sold (in thousands)	22,842			4,734			6,399			97
MWh generated (in thousands)	21,870			4,077			5,008			97
Average on-peak market power prices ($/MWh)	$	40.58		$	52.87		$	43.31		$	41.64

	Six months ended June 30,
Weather Metrics	Texas			Northeast			South Central			West
2011
CDDs	1,320			164			662			70
HDDs	1,171			3,892			2,113			2,141
2010
CDDs	1,026			215			689			75
HDDs	1,464			3,447			2,423			2,004
30 year average
CDDs	948			105			489			157
HDDs	1,205			3,931			2,194			1,965


•	Generation gross margin — decreased by $483 million, on a consolidated basis, during the six months ended June 30, 2011, compared to the same period in 2010. Including intercompany sales, generation gross margin decreased by $308 million, due to:



Decrease in Texas region	$	(178	)
Decrease in Northeast region	(164		)
Increase in South Central region	16
Increase in West region	8
Other	10
	$	(308	)

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



Lower energy revenue due to a 12% decrease in average realized energy prices, which reflects lower hedged prices in 2011	$	(174	)
Higher coal costs due to a 10% increase in coal prices from higher fuel surcharges	(31		)
Higher natural gas costs due to a 3% increase in average prices, which reflect increased market prices	(4		)
Favorable impact from a 3% increase in coal generation driven by higher economic dispatch and lower planned outages, offset by higher unplanned outages	16
Favorable impact from a 45% increase in wind generation primarily from the acquisition of South Trent in 2010	12
Favorable impact due to a 4% increase in nuclear generation driven by fewer unplanned outages in 2011	9
Favorable impact due to a 16% increase in natural gas generation driven by warmer weather compared to 2010	4
Higher purchased energy costs from increased obligations when baseload plants are unavailable	(10		)
	$	(178	)

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



Lower energy revenue due to a 27% decrease in realized prices, driven by decreased hedged prices in 2011	$	(75	)
Lower energy revenue due to a 4% decrease in generation, primarily at the region's coal plants due to the retirement of two units at Indian River offset by an increase in generation at Arthur Kill, which benefited from local transmission outages	(16		)
Lower capacity revenue due to higher forced outage rates and decreased prices of 3%	(30		)
Lower capacity revenue due to an 81% decrease in LFRM prices and a 30% decrease in LFRM capacity sold	(18		)
Lower capacity revenue from the expiration of RMR contracts for Montville, Middletown, and Norwalk	(7		)
Higher natural gas and oil costs due to a 53% increase in generation, primarily at Arthur Kill	(9		)
Lower coal costs due to an 11% decrease in coal generation	13
Higher coal costs due to 7% higher average prices, driven by higher transportation costs	(7		)
Net impact on gross margin of new load serving contracts commencing on June 1, 2010	(8		)
Decrease in unrealized trading revenue	(8		)
Other	1
	$	(164	)

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



Higher merchant revenue due to a 61% increase in MWh sold, primarily related to two additional Cottonwood units	$	27
Higher merchant revenue related to a 7% increase in average realized prices	5
Higher contract revenue from new contracts with three regional municipalities	16
Higher capacity revenue due primarily to contributions from the Rockford Plants in the PJM market and higher cooperative billing peaks	7
Higher natural gas costs related to the addition of the Cottonwood facility to the regional portfolio	(25		)
Higher coal costs due to a 9% increase in generation at the region's coal plant, which reflects additional outage work in 2010	(11		)
Higher coal costs due to an increase in prices driven by higher transportation cost compared to 2010	(5		)
Other	2
	$	16

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



Higher capacity revenue due to additional sales at El Segundo and a price increase on the Cabrillo I tolling agreement	$	3
Lower cost of sales primarily due to a 20% decrease in natural gas prices	2
Increase in other revenue due to fuel oil sales at Encina	2
Other	1
	$	8

Retail gross margin

The Company's retail gross margin, which reflects retail operating revenues less retail cost of sales, includes the results of NRG's Reliant Energy business segment, as well as the results of Green Mountain Energy which is included in NRG's Corporate business segment.



	Six months ended June 30, 2011
(In millions)	Reliant Energy		Green Mountain ^(a)		Eliminations			Consolidated Total
Retail operating revenues	$	2,348	$	298	$	(2	)	$	2,644
Retail cost of sales	1,800		219		(727		)	1,292
(a) Green Mountain Energy was acquired in November 2010.

			Six months ended June 30, 2010
(In millions)			Reliant Energy		Eliminations			Consolidated Total
Retail operating revenues			$	2,586	$	—		$	2,586
Retail cost of sales			1,985		(553		)	1,432

Reliant Energy

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

Selected Income Statement Data



	Six months ended June 30,
(In millions except otherwise noted)	2011		2010
Operating Revenues
Mass revenues	$	1,386	$	1,521
Commercial and Industrial revenues	900		991
Supply management revenues	62		74
Retail operating revenues ^(a)	2,348		2,586
Retail cost of sales ^(b)	1,800		1,985
Retail gross margin	$	548	$	601

Business Metrics
Electricity sales volume — GWh
Mass	10,769		10,546
Commercial and Industrial ^(a)	12,365		12,892
Average retail customers count (in thousands, metered locations)
Mass	1,469		1,512
Commercial and Industrial^(a)	60		64
Retail customers count (in thousands, metered locations)
Mass	1,477		1,488
Commercial and Industrial^(a)	61		63

Weather Metrics
CDDs ^(c)	1,466		1,180
HDDs^(c)	987		1,268


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


(b)	Includes intercompany purchases from the Texas region of $663 million and $553 million, respectively.


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


•	Retail gross margin — Reliant Energy's gross margin decreased $53 million for the six months ended June 30, 2011, compared to the same period in 2010, driven by:



Favorable weather impact driven by warmer weather in 2011 yielding 4% higher overall Mass customer usage, partially offset by 21% lower gross margin per MWh on the incremental weather volumes	$	12
3% fewer Mass customers primarily driven by 0.1% net attrition between July 2010 and June 2011	(23		)
Decrease in Mass revenue rates due to lower pricing on acquisitions and renewals consistent with competitive offers	(127		)
Decrease in C&I revenue rates of 5% due to lower pricing consistent with competitive offers as well as lower rates on variable contracts due to lower index prices	(44		)
Decrease in supply costs due to 6% lower hedged prices	178
Decrease in supply management revenue	(12		)
Estimated favorable impact in 2010 as compared to 2011 from the termination of out-of-market supply contracts in conjunction with 2009 CSRA unwind	(45		)
Other	8
	$	(53	)


•	Trends — Mass customer counts increased by approximately 17,000 since December 31, 2010, indicating a stabilization of customer attrition. Favorable weather in both periods resulted in higher customer usage of 16% in 2011 and 11% in 2010 when compared to ten-year normal weather.

Green Mountain Energy

The following is a discussion of retail gross margin for Green Mountain Energy for the six months ended June 30, 2011:



Retail operating revenues	$	298
Retail cost of sales ^(a)	219
Retail gross margin	$	79
(a) Includes intercompany purchases of $64 million

•

Retail gross margin — Green Mountain Energy's gross margin of $79 million for the six months ended June 30, 2011 reflects increased customer usage due to the favorable impact of colder than normal weather in the first quarter, as compared to the 30-year HDD average, and warmer than normal weather in the second quarter, as compared to the 30-year CDD average. Revenues were generated 63% and 37% from residential and commercial customers, respectively. Total metered customer counts were approximately 0.4 million and increased approximately 10%, or 34,000, in the six months ended June 30, 2011.

Mark-to-market for Economic Hedging Activities

Mark-to-market for economic hedging activities includes asset-backed hedges that did not qualify for cash flow hedge accounting and ineffectiveness on cash flow hedges. Total net mark-to-market results increased by $201 million during the six months ended June 30, 2011, compared to the same period in 2010.

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



	Six months ended June 30, 2011
	Reliant Energy			Texas			Northeast			South Central			West			Thermal		Corporate ^(a)			Elimination^(b)			Total
	(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(1	)	$	(69	)	$	11		$	13		$	(1	)	$	—	$	—		$	50		$	3
Net unrealized gains/(losses) on open positions related to economic hedges	3			79			3			(6		)	8			—		—			(22		)	65
Total mark-to-market gains in operating revenues	$	2		$	10		$	14		$	7		$	7		$	—	$	—		$	28		$	68
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	79		$	2		$	(4	)	$	(1	)	$	—		$	—	$	(7	)	$	(50	)	$	19
Reversal of loss positions acquired as part of the Reliant Energy acquisition as of May 1, 2009	47			—			—			—			—			—		—			—			47
Reversal of loss positions acquired as part of the Green Mountain Energy acquisition as of November 5, 2010	—			—			—			—			—			—		24			—			24
Net unrealized (losses)/gains on open positions related to economic hedges	(27		)	16			4			8			—			—		(5		)	22			18
Total mark-to-market gains in operating costs and expenses	$	99		$	18		$	—		$	7		$	—		$	—	$	12		$	(28	)	$	108

(a) Corporate segment consists of Green Mountain Energy activity.

(b) Represents the elimination of the intercompany activity between the Texas or Northeast regions with Green Mountain Energy or Reliant Energy.



	Six months ended June 30, 2010
	Reliant Energy			Texas			Northeast			South Central			West		Thermal			Corporate		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	$	—		$	(53	)	$	(58	)	$	1		$	—	$	(2	)	$	—	$	(9	)	$	(121	)
Net unrealized gains/(losses) on open positions related to economic hedges	—			156			2			(22		)	1		—			—		(79		)	58
Total mark-to-market gains/(losses) in operating revenues	$	—		$	103		$	(56	)	$	(21	)	$	1	$	(2	)	$	—	$	(88	)	$	(63	)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(20	)	$	23		$	9		$	9		$	—	$	—		$	—	$	9		$	30
Reversal of loss positions acquired as part of the Reliant Energy acquisition as of May 1, 2009	150			—			—			—			—		—			—		—			150
Net unrealized (losses)/gains on open positions related to economic hedges	(255		)	17			6			11			—		—			—		79			(142		)
Total mark-to-market (losses)/gains in operating costs and expenses	$	(125	)	$	40		$	15		$	20		$	—	$	—		$	—	$	88		$	38


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

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

For the six months ended June 30, 2011, the net gains on open positions were due to a decrease in forward power and gas prices. Reliant Energy's $47 million gain from the roll-off of acquired derivatives consists of loss positions that were acquired as of May 1, 2009, and valued using forward prices on that date. Green Mountain Energy's $24 million gain from the roll-off of acquired derivatives consists of loss positions that were acquired as of November 5, 2010, and valued using forward prices on that date. The roll-off amounts were offset by realized losses at the settled prices and higher costs of physical power which are reflected in operating costs and expenses during the same period.

For the six months ended June 30, 2010, the net losses on open positions were due to a decrease in forward power and gas prices. This was partially offset by an increase in the value of forward sales of natural gas and electricity. Reliant Energy's $150 million gain from the roll-off of acquired derivatives consists of loss positions that were acquired as of May 1, 2009, and valued using forward prices on that date. The roll-off amounts were offset by realized losses at the settled prices and higher costs of physical power which are reflected in operating costs and expenses during the same period.

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the six months ended June 30, 2011, and 2010. The realized financial and physical trading results are included in operating revenue and the unrealized financial and physical trading results are included in other revenue. The Company's trading activities are subject to limits within the Company's Risk Management Policy.



	Six months ended June 30,
(In millions)	2011		2010
Trading gains/(losses)
Realized	$	15	$	(24	)
Unrealized	36		49
Total trading gains	$	51	$	25

Contract Amortization Revenue

Contract amortization represents the roll-off of in-market customer contracts valued under purchase accounting and the decrease of $23 million as compared to the prior period in 2010 related primarily to lower contract amortization of $47 million for Reliant Energy, offset by higher contract amortization of $19 million for Green Mountain Energy.

Contract and Emissions Credit Amortization

Contract and emissions credit amortization increased by $17 million, primarily due to lower amortization, which is an offset to expense, in the current year for energy supply contracts that were valued as part of the purchase accounting for Reliant Energy.

Other Operating Costs



(In millions)	Reliant Energy	Texas	Northeast	South Central	West	Thermal	Other	Total
Six months ended June 30, 2011	$90	$257	$107	$43	$36	$19	$11	$563
Six months ended June 30, 2010	$94	$270	$133	$50	$32	$18	$5	$602

Other operating costs decreased by $39 million for the six months ended June 30, 2011, compared to the same period in 2010, due to:



	(In millions)
Decrease in Northeast region operations and maintenance expense	$	(39	)
Decrease in South Central region operations and maintenance expense	(10		)
Decrease in Texas region operations and maintenance expense	(13		)
Other increases in operations and maintenance expense	10
Increase in property tax expense	8
Other	5
	$	(39	)

◦

Northeast operations and maintenance — decreased as the prior year period included a $12 million charge related to the write-off of previously capitalized costs on the Indian River Unit 3 back-end controls project together with associated cancellation penalties, due to the decision not to proceed with the project following the agreement with DNREC to retire the unit by the end of 2013. In addition, there was a decrease of $8 million in operational labor from headcount reductions, a decrease in normal and major maintenance of $11 million, and prior year write-offs of approximately $7 million at Arthur Kill, Keystone and Conemaugh.


◦	South Central operations and maintenance — decreased primarily due to the scope and timing of outage work at Big Cajun II in 2010.


◦	Texas operations and maintenance — decreased as a result of less maintenance work during planned outages at the region's baseload plants as compared to the same period in 2010.


◦	Other operations and maintenance — increased as a result of increased maintenance work due to the acquisition of Green Mountain Energy and due to planned outages as compared to the same period in 2010.


◦	Property tax expense — increased primarily due to a decrease of $7 million in New York Empire Zone tax credits as compared to 2010.

Depreciation and Amortization Expense

Depreciation and amortization expense increased by $17 million for the six months ended June 30, 2011, compared to the same period in 2010 due primarily to the acquisitions of Cottonwood, Green Mountain Energy, and Northwind Phoenix in 2010.

Selling, General and Administrative Expenses

Selling, general and administrative expenses increased by $41 million for the six months ended June 30, 2011, compared to the same period in 2010 due primarily to the acquisition of Green Mountain Energy in November 2010. Green Mountain Energy's selling, general and administrative costs were $38 million for the six months ended June 30, 2011. In addition, selling, general and administrative expenses increased due to increased marketing costs associated with additional advertising campaigns and sponsorship arrangements. This increase was offset in part by a decrease in bad debt expense of $10 million at Reliant Energy due to improved customer payment behavior and decreased revenues.

Gain on Sale of Assets

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

Equity in Earnings of Unconsolidated Affiliates

NRG's equity earnings from unconsolidated affiliates decreased by $15 million for the six months ended June 30, 2011, compared to the same period in 2010. The decrease is due primarily to the changes in fair value of Sherbino's forward gas contract of $16 million and a decrease in equity earnings from Gladstone of $9 million, offset by equity earnings of $6 million from GenConn and $3 million from Saguaro.

Impairment Charge on Investment

As discussed in more detail in Note 5, Nuclear Innovation North America LLC Developments, Including Impairment Charge, in this Form 10-Q, 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 recorded an impairment charge of $492 million in the six months ended June 30, 2011.

Other Income, net

Other income, net, decreased by $15 million for the six months ended June 30, 2011, compared to the same period in 2010, which relates primarily to foreign exchange gains recognized in the prior period.

Loss on Debt Extinguishment

A loss on the extinguishment of the 2014 Senior Notes and the 2016 Senior Notes of $143 million was recorded in the six months ended June 30, 2011, which primarily consisted of the premiums paid on the redemption and the write-off of previously deferred financing costs.

Interest Expense

NRG's interest expense increased by $40 million for the six months ended June 30, 2011, compared to the same period in 2010 due to the following:



Increase/(decrease) in interest expense	(In millions)
Increase for 2020 Senior Notes issued in August 2010	$	45
Increase for 2018 Senior Notes issued in January 2011	39
Increase for 2019 and 2021 Senior Notes issued in May 2011	16
Increase for project financings	7
Increase for tax-exempt bonds	7
Decrease for capitalized interest	(28		)
Decrease for 2014 Senior Notes redeemed in January and February 2011	(29		)
Decrease for 2016 Senior Notes redeemed in May and June 2011	(14		)
Other	(3		)
Total	$	40

Income Tax (Benefit)/Expense

For the six months ended June 30, 2011, NRG recorded an income tax benefit of $735 million as a result of a pre-tax loss of $374 million. For the same period in 2010, NRG recorded income tax expense of $182 million on pre-tax income of $450 million. The effective tax rate was 196.5% and 40.4% for the six months ended June 30, 2011, and 2010, respectively.

For the six months ended June 30, 2011, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to a benefit of $612 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 in June 2011 and that were mainly composed of net operating losses of $536 million which had been classified as capital loss carryforwards for financial statement purposes. In addition, a valuation allowance net decrease of $23 million increased the effective tax rate. For the six months ended June 30, 2010, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to state and local income taxes, as well as recording federal and state tax expense and interest for uncertain tax benefits.

Liquidity and Capital Resources

Liquidity Position

As of June 30, 2011, and December 31, 2010, NRG's liquidity, excluding collateral received, was approximately $3.3 billion and $4.3 billion respectively, and comprised of the following:



(In millions)	June 30, 2011			December 31, 2010
Cash and cash equivalents	$	1,939		$	2,951
Funds deposited by counterparties	260			408
Restricted cash	145			8
Total cash	2,344			3,367
Funded Letter of Credit Facility availability	316			440
Revolving Credit Facility availability	853			853
Total liquidity	3,513			4,660
Less: Funds deposited as collateral by hedge counterparties	(260		)	(408		)
Total liquidity, excluding collateral received	$	3,253		$	4,252

For the six months ended June 30, 2011, total liquidity, excluding collateral received, decreased by $999 million due to lower cash and cash equivalent balances of $1.0 billion. Changes in cash and cash equivalent balances are further discussed below under the heading Cash Flow Discussion. Cash and cash equivalents and funds deposited by counterparties at June 30, 2011, were predominantly held in money market funds invested in treasury securities, treasury repurchase agreements or government agency debt.

Included in restricted cash is $70 million of cash and cash equivalents held in controlled accounts. As discussed more fully in Note 4, Business Acquisitions and Disposition, this represents collateral to support the Company's equity funding obligation for Ivanpah and is a requirement of the U.S. DOE, which guarantees Ivanpah's debt. This collateral can be replaced, at the Company's discretion, with a letter of credit in order to utilize such amounts for other purposes. The Company's total liquidity excluding such amounts is $3.2 billion.

The line item “Funds deposited by counterparties” represents the amounts that are held by NRG as a result of collateral posting obligations from the Company's counterparties due to positions in the Company's hedging program. These amounts are segregated into separate accounts that are not contractually restricted but, based on the Company's intention, are not available for the payment of NRG's general corporate obligations. Depending on market fluctuation and the settlement of the underlying contracts, the Company will refund this collateral to the counterparties pursuant to the terms and conditions of the underlying trades. Since collateral requirements fluctuate daily and the Company cannot predict if any collateral will be held for more than twelve months, the funds deposited by counterparties are classified as a current asset on the Company's balance sheet, with an offsetting liability for this cash collateral received within current liabilities. The change in "Funds deposited by counterparties" from December 31, 2010, was due to the roll-off of gas hedges in the six months ended June 30, 2011.

As discussed more fully in Note 9, Long-Term Debt, to this Form 10-Q, on July 1, 2011, NRG replaced its Senior Credit Facility, consisting of its Term Loan Facility, Revolving Credit Facility and Funded Letter of Credit Facility, with the 2011 Senior Credit Facility.

Management believes that the Company's liquidity position and cash flows from operations will be adequate to finance operating and maintenance capital expenditures, to fund dividends to NRG's preferred shareholders, and other liquidity commitments. Management continues to regularly monitor the Company's ability to finance the needs of its operating, financing and investing activity within the dictates of prudent balance sheet management.

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 9, Long-Term Debt, to this Form 10-Q and Note 12, Debt and Capital Leases, to the Company's 2010 Form 10-K, the Company's financing arrangements consist mainly of the Senior Credit Facility, the Senior Notes, project-related financings and the GenConn Energy LLC 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-money hedge agreements for forward sales of power or MWh equivalents. To the extent that the underlying hedge positions for a counterparty are in-the-money to NRG, the counterparty would have no claim under the lien program. The lien program limits the volume that can be hedged, not the value of underlying out-of-money positions. The first lien program does not require NRG to post collateral above any threshold amount of exposure. Within the first 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 or NRG and has no stated maturity date.

The Company's lien counterparties may have a claim on its assets to the extent market prices exceed the hedged price. As of June 30, 2011, all hedges under the first liens were in-the-money for NRG on a counterparty aggregate basis.

The following table summarizes the amount of MWs hedged against the Company's baseload assets and as a percentage relative to the Company's baseload capacity under the first lien structure as of June 30, 2011:



Equivalent Net Sales Secured by First Lien Structure ^(a)	2011		2012		2013		2014
In MW ^(b)	2,249		1,607		140		8
As a percentage of total net baseload capacity ^(c)	33	%	24	%	2	%	—


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


(b)	2011 MW value consists of August 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 maintenance, environmental and RepoweringNRG; and (iv) corporate financial transactions including return of capital to shareholders.

Commercial Operations

NRG’s commercial operations activities require a significant amount of liquidity and capital resources. These liquidity requirements are primarily driven by: (i) margin and collateral posted with counterparties; (ii) initial collateral required to establish trading relationships; (iii) timing of disbursements and receipts (i.e., buying fuel before receiving energy revenues); (iv) initial collateral for large structured transactions; and (v) collateral for project development. As of June 30, 2011, commercial operations had total cash collateral outstanding of $254 million, and $910 million outstanding in letters of credit to third parties primarily to support its commercial activities for both wholesale and retail transactions (includes a $61 million letter of credit relating to deposits at the PUCT that covers outstanding customer deposits and residential advance payments). As of June 30, 2011, total collateral held from counterparties was $260 million in cash and $9 million of letters of credit.

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

Capital Expenditures

The following table and descriptions summarize the Company's capital expenditures, including accruals, for maintenance, environmental and RepoweringNRG, other than nuclear development, for the six months ended June 30, 2011, and the estimated capital expenditures and repowering investments forecast for the remainder of 2011.



(In millions)	Maintenance		Environmental		Repowering		Total
Northeast	$	4	$	91	$	—	$	95
Texas	60		—		7		67
South Central	12		—		—		12
West	11		—		680		691
Reliant Energy	7		—		—		7
Other	13		—		5		18
Total for the six months ended June 30, 2011	$	107	$	91	$	692	$	890
Estimated capital expenditures for the remainder of 2011	$	110	$	95	$	1,556	$	1,761

•

RepoweringNRG capital expenditures — For the six months ended June 30, 2011, the Company's RepoweringNRG capital expenditures included $547 million for solar projects and $133 million for the Company's El Segundo project. In 2011, NRG will be investing in a number of solar projects and continuing its efforts at El Segundo. Subject to financial close, these solar projects, for which the purchase price of certain projects will be $154 million and future capital expenditures are estimated to be approximately $1.4 billion, will be funded from a number of sources including third party partners, bank financing which will be backed by loan guarantees from the U.S. DOE, and NRG contributions.

•

Maintenance and environmental capital expenditures — For the six months ended June 30, 2011, the Company's maintenance capital expenditures included $37 million in nuclear fuel expenditures related to STP Units 1 & 2. In addition, $80 million of environmental capital expenditures for the 2011 year-to-date period relate to a project to install selective catalytic reduction systems, scrubbers and fabric filters on Indian River Unit 4, with an expected in-service date of year-end 2011.

Environmental Capital Expenditures

Based on current rules, technology and plans, NRG has estimated that environmental capital expenditures from 2011 through 2015 to meet NRG's environmental commitments will be approximately $721 million (of which $180 million will be financed through draws on the Indian River tax exempt facilities) and are primarily associated with controls on the Company's Big Cajun and Indian River facilities. These capital expenditures, in general, are related to installation of particulate, SO₂, NO_x, and mercury controls to comply with federal and state air quality rules and consent orders, as well as installation of BTA under the proposed 316(b) Rule. NRG continues to explore cost effective compliance alternatives. This estimate reflects anticipated schedules and controls related to CATR, Mercury and Air Toxics Standards and the 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; however, NRG believes it is positioned to meet more stringent requirements through its planned capital expenditures, existing controls, and the use of Powder River Basin coal.

2011 Capital Allocation Program

On February 22, 2011, the Company announced its 2011 Capital Allocation Plan to purchase $180 million in common stock. On April 29, 2011, the Company completed the repurchase of 6,229,574 shares of NRG common stock for $130 million under an ASR Agreement. On August 4, 2011, the Company announced additional share repurchases of $250 million under the Capital Allocation Plan, bringing the total targeted share repurchases for 2011 to $430 million. The Company intends to complete its remaining $300 million of share repurchases by the end of 2011, subject to market prices, financial restrictions under the Company's debt facilities and as permitted by securities laws.

As part of the 2011 plan, the Company expects to invest approximately $403 million in maintenance and environmental capital expenditures in existing assets, and approximately $2.6 billion in solar and other projects under RepoweringNRG, of which $208 million and $866 million have been spent by June 30, 2011, respectively. Investing in NRG's large solar projects is conditional on obtaining U.S. DOE loan guarantees that will fund a large portion of the capital investments, coupled with investments by third party partners and NRG equity contributions. On April 5, 2011, the Company obtained a U.S. DOE loan guarantee for its Ivanpah project and still awaits financial close for the remaining CVSR and Agua Caliente projects.

Finally, in addition to scheduled debt amortization payments, in the first quarter 2011 the Company paid its first lien lenders $149 million of its 2010 excess cash flow, as defined in the Senior Credit Facility.

Simplifying Capital Structure

The Company intends to refinance its remaining $1.1 billion of 2017 Senior Notes to simplify its capital structure, better align covenant packages and extend debt maturities. Upon completion of this undertaking, a single covenant package across credit facilities and debt securities will enable NRG to invest more opportunistically in growth initiatives and enhance its ability to efficiently return capital to all investors. The 2017 Senior Notes refinancing will depend on market conditions and is therefore subject to change.

Cash Flow Discussion

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



(In millions)
Six months ended June 30,	2011			2010			Change
Net cash provided by operating activities	$	309		$	605		$	(296	)
Net cash used by investing activities	(1,059		)	(385		)	(674		)
Net cash used by financing activities	(268		)	(347		)	79

Net Cash Provided By Operating Activities

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



Net reduction in cash paid for collateral	$	99
Net reduction in option premiums	(107		)
Decrease in operating income adjusted for non-cash charges	(306		)
Other changes in working capital	18
	$	(296	)

Net Cash Used By Investing Activities

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



Increase in capital expenditures due to increased spending on maintenance and RepoweringNRG, primarily for solar projects in construction	$	(509	)
Increase in restricted cash	(101		)
Decrease in cash paid for acquisitions, which primarily reflects Ivanpah in 2011 compared to South Trent and Northwind Phoenix in 2010	73
Decrease in purchases of emissions allowances	28
Receipt of cash for land sales in 2011	13
Receipt of cash for the sale of assets in 2010, which was mainly for the sale of Padoma	(30		)
Receipt of cash grants in 2010	(102		)
Investments in unconsolidated affiliates, primarily related to investments in a clean technology joint venture	(15		)
Other	(31		)
	$	(674	)

Net Cash Used By Financing Activities

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



Increase in cash paid to repurchase shares of NRG common stock	$	(80	)
Increase in net cash paid/received for the settlement of acquired derivatives with financing elements	(73		)
Net increase in the proceeds from the issuance of debt, primarily related to the repayment of the CSF debt in 2010	283
Receipt of cash from noncontrolling interest in 2010	(50		)
Other	(1		)
	$	79

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

For the six months ended June 30, 2011, the Company had generated a domestic pre-tax book loss of $392 million and foreign pre-tax book income of $18 million. As of June 30, 2011, the Company has cumulative domestic NOL carryforwards of $130 million for financial statement purposes. In addition, the Company has cumulative foreign NOL carryforwards of $287 million, of which $86 million will expire starting 2011 through 2018 and of which $201 million do not have an expiration date.

In addition to these amounts, the Company has $128 million of tax effected uncertain tax benefits which relate primarily to positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductions. 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 $50 million in 2011.

However, as the position remains uncertain for the $128 million of tax effected uncertain tax benefits, the Company has recorded a non-current tax liability of $53 million and may accrue the remaining balance as an increase to non-current liabilities until final resolution with the related taxing authority. The $53 million non-current tax liability for uncertain tax benefits results primarily from positions taken on various state returns, including accrued interest.

In the 2011 second quarter, the Company received the final audit report effectively closing the Internal Revenue Service's audit examination for the years 2004 through 2006. The Company believes the matters addressed under audit are effectively settled in accordance with ASC 740 and recognized a benefit of $612 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 in June 2011 and that were mainly composed of net operating losses of $536 million which had been classified as capital loss carryforwards for financial statement purposes. The Company continues to be under examination for various state jurisdictions for multiple years.

New and On-going Company Initiatives and Development Projects

RepoweringNRG Update

Conventional Power Development

The Company's El Segundo Energy Center LLC, or ESEC, has begun site preparation work at its El Segundo Power Generating Station in El Segundo, California. Full notice to proceed with construction of the 550 MW fast start, gas turbine combined cycle generating facility was provided to the construction vendor on June 6, 2011. Construction of the 550 MW fast start, gas turbine combined cycle generating facility commenced in the second quarter 2011. The Company expects a commercial operation date of August 1, 2013.

GenConn, a 50/50 joint venture of NRG and The United Illuminating Company, or United Illuminating, was formed to construct, own and operate two 200 MW peaking generation facilities in Connecticut at NRG's Devon and Middletown sites. The GenConn Devon facility reached commercial operations in 2010. Construction of the Middletown facility is substantially complete with all four generating units becoming operational and participating in the ISONE market in June 2011.

In early 2011, New Jersey enacted legislation requiring the New Jersey Board of Public Utilities, or BPU, to implement a Long-Term Capacity Agreement Pilot Program, or LCAPP, and to conduct a competitive procurement for up to 2,000 MW of new, base load or mid-merit generation facilities. Pursuant to the legislation, on February 10, 2011 the BPU initiated the LCAPP Proceeding, and the associated competitive procurement process. The Company's subsidiary New Jersey Power Development LLC, or NJPD, submitted a proposal to construct a 660 MW combined-cycle generation project in Old Bridge, New Jersey. On March 29, 2011, NJPD's project was one of three projects selected by the BPU to participate in the LCAPP. As a result of that award, on April 28, 2011, NJPD executed a Standard Offer Capacity Agreement with each of the state's electric distribution companies. NJPD filed its Air Permit Application on May 26, 2011, and is moving forward with development activities. However, the LCAPP program remains challenged because of recent FERC changes in the PJM Base Residual Auction rules related to the Minimum Offer Price Rule as more fully discussed under Item 2 — Regulatory Matters - PJM, to this Form 10-Q.

Renewable Development

As part of its core strategy, NRG intends to invest significantly in the development and acquisition of renewable energy projects, including solar, wind and biomass, as described more fully in Part I, Item 1 — Renewable Development and Acquisitions, to the Company's 2010 Form 10-K. A brief description of the Company's recent development efforts with respect to each 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 major utility-scale solar projects as of June 30, 2011, that the Company (i) currently owns and is developing or (ii) has entered into an agreement with the project sponsor wherein the Company will have a right to own and develop the project.



NRG Owned Projects	Location	PPA	MW ^(a)	Expected COD	Status
Avenal	Kings County, CA	20 year	45	2011	Under Construction
Roadrunner	Santa Teresa, NM	20 year	20	2011	Under Construction
Ivanpah	Ivanpah, CA	20 - 25 year	392	2013	Under Construction
Projects Under Agreement
Agua Caliente	Yuma County, AZ	25 year	290	2012 - 2014	Under Construction
CVSR	San Luis Obispo, CA	25 year	250	2011 - 2013	Pre Construction

(a) Represents total project size.

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

Avenal — The Company, together with its 50/50 joint venture partner Eurus Energy America, will build a PV generating facility in California, with a capacity of 45 MW. The project has secured construction financing on all three sites, and expects to achieve commercial operations during the third quarter 2011.

Roadrunner — This project, which is wholly-owned, has secured construction financing and expects to achieve commercial operation by the end of third quarter 2011.

Ivanpah — On April 5, 2011, the Company executed definitive agreements to become the 50.1% lead investor, along with BrightSource Energy, Inc., or BSE, and Google, Inc., or Google, in the 392 MW Ivanpah Solar Electric Generating System, or Ivanpah. The Company has partnered with BSE and Google to construct, finance and operate the largest solar thermal technology project in the world. Ivanpah, which commenced construction in the fourth quarter of 2010, has received a $1.6 billion loan guarantee from the U.S. DOE. Construction of the Ivanpah project began in October 2010 and operations for the first phase are scheduled to commence in the first quarter of 2013, with the second and third phases expected to reach commercial operations in the second and third quarters of 2013, respectively. On June 10, 2011, the U.S. Fish and Wildlife Service, or FWS, issued a revised biological opinion with respect to the Ivanpah Project. Construction on the Ivanpah Project remains close to schedule and is expected to achieve commercial operation on a timely basis. Through June 30, 2011, the Company has invested $75 million in the project while posting $192 million of collateral, which includes $70 million in cash and $122 million in a letter of credit, in connection with the total equity commitment of up to $300 million.

Western Watershed Project filed a motion seeking a temporary restraining order against the Ivanpah Project on June 27, 2011 to shut the project down in order to protect the desert tortoise as well as other animals. A hearing was held on June 30, 2011, at which time the judge denied plaintiff's request for a temporary restraining order. A hearing on plaintiff's request for a preliminary injunction was held on August 1, 2011, and no decision has been issued.

Agua Caliente — On January 20, 2011, the U.S. DOE announced the offer of a conditional commitment to Agua Caliente for a loan guarantee of up to $967 million. NRG plans to invest up to $800 million in the project through 2014 after executing definitive documentation which is anticipated in the third quarter of 2011.

CVSR — On April 12, 2011, the U.S. DOE announced the offer of a conditional commitment to SunPower Corporation for a loan guarantee of up to $1.187 billion. Subject to final total project cost and further negotiation of financing terms and conditions, the Company plans to invest up to $450 million in the project over the next four years. Construction is expected to begin in the third quarter of 2011, contingent on a number of factors, including the receipt of all applicable permits. Through June 30, 2011, the Company has funded $15 million in pre-acquisition and joint development costs with SunPower Corporation, which will be credited against the future project acquisition price.

Distributed Solar

NRG's efforts had focused on larger (by renewable standards) “utility” sized solar projects. However, in September 2010, the Company announced its involvement in smaller scale “distributed” solar in Arizona. That program involves the building of solar pavilions at school districts and municipal offices primarily in the areas of Phoenix and Tucson. These projects generally sell their output to the school districts and municipalities under longer term PPAs of 15-20 years. As of June 30, 2011, the Company has 2.8MW of distributed solar in commercial operations and a further 3.5MW under construction. Included in the construction total is an agreement to build a 2.0 MW solar installation at FedEx Field, selling that power to the Washington Redskins under a 10 year PPA with a 10 year renewal term. The facility is anticipated to reach commercial operations in September 2011. On July 8, 2011, the Company executed agreements to acquire the rights to build a 2.1MW solar installation at a parking lot on the grounds of Arizona State University. Energy from the facility will be sold to the Arizona Board of Regents on behalf of the University under a 25 year PPA, with commercial operations anticipated by the end of 2011.

In June 2011, the Company made an equity commitment in respect to a 15 MW (Part I, Phase I) portion of a distributed generation project, referred to as Project Amp, led by Prologis, Inc. Subject to further negotiation of financing terms and conditions as well as equity documentation, the Company plans to invest up to $22.5 million in respect to Part I, Phase I of the Project. On June 22, 2011, the U.S. DOE announced the offer of a conditional loan guarantee commitment to Prologis, Inc. of up to $1.4 billion, which would facilitate a total project size of up to 733 MW.

Solar Development Pipeline

In June 2010, NRG acquired a pipeline of solar development projects from US Solar Ventures. These development projects originally totaled 450 MW at the time of acquisition and now total 734 MW after optimization of the portfolio with NRG Solar's own project pipeline. The projects range in size from 20 MW to 238 MW, and have the potential to be operational between 2012 and 2014. The Borrego Solar project is a 26 MW PV solar facility that originated from the development pipeline and has executed a 25-year PPA with San Diego Gas and Electric. The Borrego Solar project expects to obtain regulatory approval from the California Public Utilities Commission in the third quarter of 2011.

The Company has an additional pipeline of solar development projects that total approximately 462 MWs, including the Alpine Solar Project, a 66 MW PV solar project with power sold to Pacific Gas & Electric under a 20-year PPA, and the Avra Valley Solar Project, formerly known as the Green Valley Solar Project, a 25 MW PV solar project with power sold to Tucson Electric Power under a 20-year PPA.

Retail Growth Initiatives

Reliant Energy continues to expand its Reliant eSense product offerings. eSense is a suite of technology solutions that use the advanced meter system network (smart meters) that is being rolled out to customers in ERCOT. Through the second quarter of 2011, Reliant has almost 350,000 customers using one of these products. In partnership with the City of Houston and Centerpoint Energy, Reliant launched Innovation Avenue during the second quarter of 2011, where Reliant installed smart energy products in customer homes. Reliant's eSense development was accelerated by the U.S. DOE grant received during 2010.

The C&I business has continued to expand into the Northeast, receiving approval to operate in the New England ISO in addition to the PJM markets in which it has been operating. Reliant has also launched its Residential business in the Northeast and is serving customers in Pennsylvania, Maryland and New Jersey.

Reliant continues selling home services products which include protection products such as surge protection, in home power line protection, HVAC maintenance and energy efficiency products like air filter delivery and solar panel leasing. NRG and Reliant are selling backup generation as a reliability service to cities, water authorities and municipal utility districts in Texas in response to a legislative mandate to have alternative power sources in the event of power loss due to hurricanes, other acts of God or power distribution related issues.

Electric Vehicle Development

On November 18, 2010, NRG announced the nation's first privately funded, comprehensive Electric Vehicle, or EV, ecosystem in Houston, the start of a rollout across Texas in 2011. Under the brand name eVgo^sm, NRG provides EV owners throughout the greater Houston area with comprehensive fueling packages and charging capability.

On April 8, 2011, NRG inaugurated the first privately funded Freedom Station^sm, including the first high-speed direct current, or DC, charger in Texas, which is also among the first in the nation. NRG plans to install a total of 70 Freedom Stations in Dallas/Fort Worth and 50 Freedom Stations in Houston by the end of 2012. NRG also plans to electrify the Interstate 45 corridor connecting these two cities in 2012.

On July 11, 2011, NRG's manufacturing vendor for the Houston and Dallas/Fort Worth networks, AeroVironment, announced the Underwriters Laboratories certification of its EV fast charging system. As such, NRG anticipates beginning the deployment of Freedom Stations in Houston and Dallas/Fort Worth in August 2011.

NRG plans to invest approximately $25 million in the Houston and Dallas/Fort Worth EV ecosystems, and will be the first company to equip an entire major market with the privately funded infrastructure needed for successful EV adoption and integration.

Carbon Capture Sequestration Project

On March 9, 2010, NRG was selected by the U.S. DOE to receive up to $167 million, including funding from the American Recovery and Reinvestment Act, to build a 60 MW post-combustion carbon capture demonstration unit at NRG's WA Parish plant southwest of Houston. NRG is currently progressing through the front-end engineering and design study, and 50% of the costs of this phase are being reimbursed by the U.S. DOE. CO₂ captured by the project will be used in enhanced oil recovery in oil fields on the Texas Gulf Coast. An application has been submitted to and approved by the U.S. DOE to conduct a front-end engineering and design study for an up-to 250MW sized project. An expanded project will allow for larger volumes of CO₂production, leading to increased oil production through enhanced oil recovery efforts. Construction is projected to begin in late 2012 with commercial operations anticipated in the fourth quarter of 2014.

Energy Technology Ventures

On January 27, 2011, NRG entered into a joint venture with GE and ConocoPhillips to invest in venture-stage and growth-stage next generation energy technology companies. The joint venture, Energy Technology Ventures, will invest in and offer commercial collaboration opportunities to emerging energy technology companies in various sectors, including renewable power generation, smart grid, energy efficiency, emission controls, oil, natural gas, coal and biofuels. As of June 30, 2011, NRG has invested in several growth companies through Energy Technology Ventures as part of its plan to invest up to $100 million in this joint venture over four years.

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 that serves as credit, liquidity or market risk support to such entity for such assets.

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 June 30, 2011, 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 June 30, 2011, NRG has several investments with an ownership interest percentage of 50% or less in energy and energy-related entities that are accounted for under the equity method of accounting. Two of these investments, GenConn and Sherbino, are variable interest entities for which NRG is not the primary beneficiary, as discussed in Note 10, 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 $258 million as of June 30, 2011. 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, to the Company's 2010 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 2010 Form 10-K. Also see Note 16, 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 six months ended June 30, 2011.

Fair Value of Derivative Instruments

NRG may enter into long-term power purchase and sales contracts, fuel purchase contracts and other energy-related financial instruments to mitigate variability in earnings due to fluctuations in spot market prices and to hedge fuel requirements at generation facilities. In addition, in order to mitigate interest rate risk associated with the issuance of the Company's variable rate and fixed rate debt, NRG enters into interest rate swap agreements. The following disclosures about fair value of derivative instruments provide an update to, and should be read in conjunction with, Fair Value of Derivative Instruments in Item 7 — Management's Discussion and Analysis of Financial Condition and Results of Operations, of the Company's 2010 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 June 30, 2011, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at June 30, 2011. The increase in NRG's net derivative asset at June 30, 2011, as compared to December 31, 2010, was driven by the decreases in gas and power prices and the roll-off of trades that settled during the period.



Derivative Activity Gains/(Losses)	(In millions)
Fair value of contracts as of December 31, 2010	$	672
Contracts realized or otherwise settled during the period	(171		)
Changes in fair value	182
Fair value of contracts as of June 30, 2011	$	683



	Fair Value of Contracts as of June 30, 2011
(In millions) 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
Level 1	$	5		$	(10	)	$	(2	)	$	—		$	(7	)
Level 2	464			295			(6		)	(37		)	716
Level 3	(39		)	12			1			—			(26		)
Total	$	430		$	297		$	(7	)	$	(37	)	$	683

The Company applies a credit reserve to reflect credit risk, which is calculated based on published default probabilities. As of June 30, 2011, the credit reserve resulted in a $2 million decrease in fair value which is composed of a $2 million loss in operating revenue and cost of operations.

Based on a sensitivity analysis, the impact of a $1 per MMBtu increase or decrease in natural gas prices across the term of the derivative contracts would cause a change of approximately $71 million in the net value of derivatives as of June 30, 2011.

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

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

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

As discussed in more detail in Note 5, Nuclear Innovation North America LLC Developments, Including Impairment Charge, to the financial statements in this Form 10-Q, 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, and consequently, NRG has recorded impairment charges of $492 million for the six months ended June 30, 2011.

ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risk is the potential loss that may result from market changes associated with the Company's merchant power generation or with an existing or forecasted financial or commodity transaction. The types of market risks NRG is exposed to in its normal business activities are commodity price risk, interest rate risk, liquidity risk, credit risk, and currency exchange risk. The following disclosures about market risk provide an update to, and should be read in conjunction with, Item 7A — Quantitative and Qualitative Disclosures About Market Risk, of the Company's 2010 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, renewable energy credits, and emissions credits. NRG manages the commodity price risk of the Company's merchant generation operations and load serving obligations by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted sales and purchases of electricity and fuel. NRG measures the risk of the Company's portfolio using several analytical methods, including sensitivity tests, scenario tests, stress tests, position reports, and Value at Risk, or VaR. NRG uses a diversified VaR model to calculate an estimate of the potential loss in the fair value of the Company's energy assets and liabilities, which includes generation assets, load obligations, and bilateral physical and financial transactions.

As of June 30, 2011, the VaR for NRG's commodity portfolio, including generation assets, load obligations and bilateral physical and financial transactions calculated using the diversified VaR model was $65 million.

The following table summarizes average, maximum and minimum VaR for NRG for the three and six months ended June 30, 2011, and 2010:



(In millions)	2011		2010
VaR as of June 30	$	65	$	51
Three months ended June 30:
Average	$	56	$	58
Maximum	65		70
Minimum	47		46
Six months ended June 30,
Average	$	53	$	53
Maximum	65		70
Minimum	44		37

In order to provide additional information for comparative purposes to NRG’s peers, the Company also uses VaR to estimate the potential loss of derivative financial instruments that are subject to mark-to-market accounting. The VaR for the derivative financial instruments calculated using the diversified VaR model as of June 30, 2011, for the entire term of these instruments entered into for both asset management and trading, was approximately $12 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.

As of June 30, 2011, the Company had various interest rate swap agreements with notional amounts totaling approximately $1.3 billion . If the swaps had been discontinued on June 30, 2011, the Company would have owed the counterparties approximately $77 million. Based on the investment grade rating of the counterparties, NRG believes its exposure to credit risk due to nonperformance by counterparties to its hedge contracts to be immaterial.

NRG has both long- and short-term debt instruments that subject the Company to the risk of loss associated with movements in market interest rates. As of June 30, 2011, a 1% change in interest rates would result in a $4 million change in interest expense on a rolling twelve month basis.

As of June 30, 2011, the fair value of the Company's long-term debt and funded letter of credit was $10.3 billion and the related carrying amount was $10.2 billion. NRG estimates that a 1% decrease in market interest rates would have increased the fair value of the Company's long-term debt and funded letter of credit by $744 million.

Liquidity Risk

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

Based on a sensitivity analysis for power and gas positions under marginable contracts, a $1 per MMBtu change in natural gas prices across the term of the marginable contracts would cause a change in margin collateral posted of approximately $138 million as of June 30, 2011, and a 0.25 MMBtu/MWh change in heat rates for heat rate positions would result in a change in margin collateral posted of approximately $11 million as of June 30, 2011. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of June 30, 2011.

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 6, Fair Value of Financial Instruments, to this Form 10-Q for discussions regarding counterparty credit risk and retail customer credit risk, and Note 8, Accounting for Derivative Instruments and Hedging Activities, to this Form 10-Q for discussion regarding credit risk contingent features.

Currency Exchange Risk

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

ITEM 4 — CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

There were no changes in the Company's internal controls over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred in the second quarter of 2011 that materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

Inherent Limitations over Internal Controls

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

PART II — OTHER INFORMATION

ITEM 1 — LEGAL PROCEEDINGS

For a discussion of material legal proceedings in which NRG was involved through June 30, 2011, see Note 16, Commitments and Contingencies, to this Form 10-Q.

ITEM 1A — RISK FACTORS

Information regarding risk factors appears in Part I, Item 1A, Risk Factors in the Company's 2010 Form 10-K.

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



For the period ended June 30, 2011	Total number of shares purchased	Average price paid per share		Total number of shares purchased as part of publicly announced plan or program	Dollar value of shares that may be purchased under the 2011 Capital Allocation Plan
First quarter 2011	—	$	—	—	$	180,000,000
April 1 - April 30	6,229,574	20.87		6,229,574	50,000,000
May 1 - May 31	—	—		—	50,000,000
June 1 - June 30	—	—		—	50,000,000
Second quarter 2011 Total	6,229,574	20.87		6,229,574	50,000,000
Year-to-date 2011	6,229,574	$	20.87	6,229,574	$	50,000,000

On February 22, 2011, the Company announced a plan to repurchase $180 million of common stock under the Company's 2011 Capital Allocation Plan. On August 4, 2011, the Company announced additional share repurchases of $250 million under the Capital Allocation Plan, bringing the total targeted share repurchases for 2011 to $430 million. The Company intends to complete its remaining $300 million of share repurchases by the end of 2011, subject to market prices, financial restrictions under the Company's debt facilities and as permitted by securities laws.

ITEM 3 — DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4 — (REMOVED AND RESERVED)

ITEM 5 — OTHER INFORMATION

On August 2, 2011, Christian S. Schade, Executive Vice President and Chief Financial Officer, formally notified NRG that he will be resigning from the Company, effective early September 2011, to assume the position of Executive Vice President and Chief Executive Officer of Omthera Pharmaceuticals, Inc., a privately held emerging specialty pharmaceuticals company.

ITEM 6 — EXHIBITS



Exhibits
1.1			Purchase Agreement, dated May 10, 2011, among NRG Energy, Inc., the guarantors named therein and Morgan Stanley & Co. Incorporated, Merrill, Lynch, Pierce, Fenner & Smith Incorporated, Barclays Capital Inc., Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., Goldman, Sachs & Co., J.P. Morgan Securities LLC, and RBS Securities Inc., as initial purchasers (incorporated by reference to Exhibit 1.1 of Form 8-K dated May 24, 2011 and filed on May 25, 2011).
4.1			Forty-Fifth Supplemental Indenture, dated as of May 20, 2011, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York (incorporated by reference to Exhibit 4.1 of Form 8-K dated May 20, 2011 and filed on May 25, 2011).
4.2			Forty-Sixth Supplemental Indenture, dated as of May 20, 2011, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York (incorporated by reference to Exhibit 4.2 of Form 8-K dated May 20, 2011 and filed on May 25, 2011).
4.3			Forty-Seventh Supplemental Indenture, dated as of May 20, 2011, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York (incorporated by reference to Exhibit 4.3 of Form 8-K dated May 20, 2011 and filed on May 25, 2011).
4.4			Forty-Eighth Supplemental Indenture, dated as of May 20, 2011, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York (incorporated by reference to Exhibit 4.4 of Form 8-K dated May 20, 2011 and filed on May 25, 2011).
4.5			Forty-Ninth Supplemental Indenture, dated as of May 20, 2011, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York (incorporated by reference to Exhibit 4.5 of Form 8-K dated May 20, 2011 and filed on May 25, 2011).
4.6			Fiftieth Supplemental Indenture, dated May 24, 2011, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York (incorporated by reference to Exhibit 4.1 of Form 8-K dated May 24, 2011 and filed on May 25, 2011).
4.7			Form of 7.625% Senior Note due 2019 (incorporated by reference to Exhibit 4.2 of Form 8-K dated May 24, 2011 and filed on May 25, 2011).
4.8			Fifty-First Supplemental Indenture, dated May 24, 2011, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York (incorporated by reference to Exhibit 4.3 of Form 8-K dated May 24, 2011 and filed on May 25, 2011).
4.9			Form of 7.875% Senior Note due 2021 (incorporated by reference to Exhibit 4.4 of Form 8-K dated May 24, 2011 and filed on May 25, 2011).
4.10			Registration Rights Agreement, dated May 24, 2011, among NRG Energy, Inc., the guarantors named therein and Morgan Stanley & Co. Incorporated, Merrill, Lynch, Pierce, Fenner & Smith Incorporated, Barclays Capital Inc., Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., Goldman, Sachs & Co., J.P. Morgan Securities LLC, and RBS Securities Inc., as initial purchasers (incorporated by reference to Exhibit 4.5 of Form 8-K dated May 24, 2011 and filed on May 25, 2011).
10.1			Amended and Restated Credit Agreement, dated as of July 1, 2011 (incorporated by reference to Exhibit 10.1 of Form 8-K dated July 1, 2011 and filed on July 5, 2011).
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/ CHRISTIAN S. SCHADE
	Christian S. Schade
	Chief Financial Officer (Principal Financial Officer)


	/s/ JAMES J. INGOLDSBY
	James J. Ingoldsby
Date: August 4, 2011	Chief Accounting Officer (Principal Accounting Officer)

EXHIBIT INDEX




Exhibits
1.1			Purchase Agreement, dated May 10, 2011, among NRG Energy, Inc., the guarantors named therein and Morgan Stanley & Co. Incorporated, Merrill, Lynch, Pierce, Fenner & Smith Incorporated, Barclays Capital Inc., Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., Goldman, Sachs & Co., J.P. Morgan Securities LLC, and RBS Securities Inc., as initial purchasers (incorporated by reference to Exhibit 1.1 of Form 8-K dated May 24, 2011 and filed on May 25, 2011).
4.1			Forty-Fifth Supplemental Indenture, dated as of May 20, 2011, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York (incorporated by reference to Exhibit 4.1 of Form 8-K dated May 20, 2011 and filed on May 25, 2011).
4.2			Forty-Sixth Supplemental Indenture, dated as of May 20, 2011, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York (incorporated by reference to Exhibit 4.2 of Form 8-K dated May 20, 2011 and filed on May 25, 2011).
4.3			Forty-Seventh Supplemental Indenture, dated as of May 20, 2011, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York (incorporated by reference to Exhibit 4.3 of Form 8-K dated May 20, 2011 and filed on May 25, 2011).
4.4			Forty-Eighth Supplemental Indenture, dated as of May 20, 2011, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York (incorporated by reference to Exhibit 4.4 of Form 8-K dated May 20, 2011 and filed on May 25, 2011).
4.5			Forty-Ninth Supplemental Indenture, dated as of May 20, 2011, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York (incorporated by reference to Exhibit 4.5 of Form 8-K dated May 20, 2011 and filed on May 25, 2011).
4.6			Fiftieth Supplemental Indenture, dated May 24, 2011, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York (incorporated by reference to Exhibit 4.1 of Form 8-K dated May 24, 2011 and filed on May 25, 2011).
4.7			Form of 7.625% Senior Note due 2019 (incorporated by reference to Exhibit 4.2 of Form 8-K dated May 24, 2011 and filed on May 25, 2011).
4.8			Fifty-First Supplemental Indenture, dated May 24, 2011, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York (incorporated by reference to Exhibit 4.3 of Form 8-K dated May 24, 2011 and filed on May 25, 2011).
4.9			Form of 7.875% Senior Note due 2021 (incorporated by reference to Exhibit 4.4 of Form 8-K dated May 24, 2011 and filed on May 25, 2011).
4.1			Registration Rights Agreement, dated May 24, 2011, among NRG Energy, Inc., the guarantors named therein and Morgan Stanley & Co. Incorporated, Merrill, Lynch, Pierce, Fenner & Smith Incorporated, Barclays Capital Inc., Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., Goldman, Sachs & Co., J.P. Morgan Securities LLC, and RBS Securities Inc., as initial purchasers (incorporated by reference to Exhibit 4.5 of Form 8-K dated May 24, 2011 and filed on May 25, 2011).
10.1			Amended and Restated Credit Agreement, dated as of July 1, 2011 (incorporated by reference to Exhibit 10.1 of Form 8-K dated July 1, 2011 and filed on July 5, 2011).
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