NRG 10-Q Quarterly Report March 31, 2011

NRG ENERGY, INC.

10-Ks and 10-Qs

10-Q	Quarter ended Sept. 30, 2025
10-Q	Quarter ended June 30, 2025
10-Q	Quarter ended March 31, 2025
10-K	Fiscal year ended Dec. 31, 2024
10-Q	Quarter ended Sept. 30, 2024
10-Q	Quarter ended June 30, 2024
10-Q	Quarter ended March 31, 2024
10-K	Fiscal year ended Dec. 31, 2023
10-Q	Quarter ended Sept. 30, 2023
10-Q	Quarter ended June 30, 2023
10-Q	Quarter ended March 31, 2023
10-K	Fiscal year ended Dec. 31, 2022
10-Q	Quarter ended Sept. 30, 2022
10-Q	Quarter ended June 30, 2022
10-Q	Quarter ended March 31, 2022
10-K	Fiscal year ended Dec. 31, 2021
10-Q	Quarter ended Sept. 30, 2021
10-Q	Quarter ended June 30, 2021
10-Q	Quarter ended March 31, 2021
10-K	Fiscal year ended Dec. 31, 2020
10-Q	Quarter ended Sept. 30, 2020
10-Q	Quarter ended June 30, 2020
10-Q	Quarter ended March 31, 2020
10-K	Fiscal year ended Dec. 31, 2019
10-Q	Quarter ended Sept. 30, 2019
10-Q	Quarter ended June 30, 2019
10-Q	Quarter ended March 31, 2019
10-K	Fiscal year ended Dec. 31, 2018
10-Q	Quarter ended Sept. 30, 2018
10-Q	Quarter ended June 30, 2018
10-Q	Quarter ended March 31, 2018
10-K	Fiscal year ended Dec. 31, 2017
10-Q	Quarter ended Sept. 30, 2017
10-Q	Quarter ended June 30, 2017
10-Q	Quarter ended March 31, 2017
10-K	Fiscal year ended Dec. 31, 2016
10-Q	Quarter ended Sept. 30, 2016
10-Q	Quarter ended June 30, 2016
10-Q	Quarter ended March 31, 2016
10-K	Fiscal year ended Dec. 31, 2015
10-Q	Quarter ended Sept. 30, 2015
10-Q	Quarter ended June 30, 2015
10-Q	Quarter ended March 31, 2015
10-K	Fiscal year ended Dec. 31, 2014
10-Q	Quarter ended Sept. 30, 2014
10-Q	Quarter ended June 30, 2014
10-Q	Quarter ended March 31, 2014
10-K	Fiscal year ended Dec. 31, 2013
10-Q	Quarter ended Sept. 30, 2013
10-Q	Quarter ended June 30, 2013
10-Q	Quarter ended March 31, 2013
10-K	Fiscal year ended Dec. 31, 2012
10-Q	Quarter ended Sept. 30, 2012
10-Q	Quarter ended June 30, 2012
10-Q	Quarter ended March 31, 2012
10-K	Fiscal year ended Dec. 31, 2011
10-Q	Quarter ended Sept. 30, 2011
10-Q	Quarter ended June 30, 2011
10-Q	Quarter ended March 31, 2011
10-K	Fiscal year ended Dec. 31, 2010
10-Q	Quarter ended Sept. 30, 2010
10-Q	Quarter ended June 30, 2010
10-Q	Quarter ended March 31, 2010
10-K	Fiscal year ended Dec. 31, 2009

PROXIES

DEF 14A	Filed on May 1, 2025
DEF 14A	Filed on March 19, 2025
DEF 14A	Filed on April 25, 2024
DEF 14A	Filed on March 15, 2024
DEF 14A	Filed on March 16, 2023
DEF 14A	Filed on April 28, 2022
DEF 14A	Filed on March 15, 2022
DEF 14A	Filed on March 15, 2021
DEF 14A	Filed on March 16, 2020
DEF 14A	Filed on March 13, 2019
DEF 14A	Filed on March 15, 2018
DEF 14A	Filed on March 16, 2017
DEF 14A	Filed on March 16, 2016
DEF 14A	Filed on March 26, 2015
DEF 14A	Filed on March 26, 2014
DEF 14A	Filed on March 13, 2013
DEF 14A	Filed on March 12, 2012
DEF 14A	Filed on March 14, 2011
DEF 14A	Filed on June 14, 2010

10-Q 1 a11-8686_110q.htm 10-Q

Table of Contents

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: March 31, 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		41-1724239
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

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

(609) 524-4500

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes 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.

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No 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 £

As of May 2, 2011, there were 241,089,416 shares of common stock outstanding, par value $0.01 per share.

Table of Contents

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		41
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		67
ITEM 4 — CONTROLS AND PROCEDURES		69
PART II — OTHER INFORMATION		70
ITEM 1 — LEGAL PROCEEDINGS		70
ITEM 1A — RISK FACTORS		70
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		70
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES		70
ITEM 4 — (REMOVED AND RESERVED)		70
ITEM 5 — OTHER INFORMATION		70
ITEM 6 — EXHIBITS		71
SIGNATURES		72

Table of Contents

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

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

· 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.

Table of Contents

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

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

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

DNREC		Delaware Department of Natural Resources and Environmental Control

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

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

IGCC		Integrated Gasification Combined Cycle

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

Table of Contents

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

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

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

Table of Contents

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

SEC		United States Securities and Exchange Commission

Securities Act		The Securities Act of 1933, as amended

Senior Credit Facility		NRG’s senior secured facility, which is comprised of a Term Loan Facility, an $875 million Revolving Credit Facility and a $1.3 billion Funded Letter of Credit Facility

Senior Notes		The Company’s $6.5 billion outstanding unsecured senior notes consisting of $2.4 billion of 7.375% senior notes due 2016, $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 and $1.1 billion of 8.25% senior notes due 2020

SO 2		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 $612 million matures on February 1, 2013, and $1.0 billion matures on August 31, 2015, and is a component of NRG’s Senior Credit Facility

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

Table of Contents

PART I — FINANCIAL INFORMATION

ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three months ended March 31,
(In millions, except for per share amounts)	2011			2010
Operating Revenues
Total operating revenues	$	1,995		$	2,215
Operating Costs and Expenses
Cost of operations	1,324			1,639
Depreciation and amortization	205			202
Selling, general and administrative	143			130
Development costs	9			9
Total operating costs and expenses	1,681			1,980
Gain on sale of assets	—			23
Operating Income	314			258
Other Income/(Expense)
Equity in (losses)/earnings of unconsolidated affiliates	(2		)	14
Impairment charge on investment	(481		)	—
Other income, net	5			4
Loss on debt extinguishment	(28		)	—
Interest expense	(173		)	(153		)
Total other expense	(679		)	(135		)
(Loss)/Income Before Income Taxes	(365		)	123
Income tax (benefit)/expense	(105		)	65
Net (Loss)/Income attributable to NRG Energy, Inc.	(260		)	58
Dividends for preferred shares	2			2
(Loss)/Income Available for Common Stockholders	$	(262	)	$	56
(Loss)/earnings per share attributable to NRG Energy, Inc. Common Stockholders
Weighted average number of common shares outstanding — basic	247			254
Net (loss)/income per weighted average common share — basic	$	(1.06	)	$	0.22
Weighted average number of common shares outstanding — diluted	247			257
Net (loss)/income per weighted average common share — diluted	$	(1.06	)	$	0.22

See notes to condensed consolidated financial statements.

Table of Contents

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

	March 31, 2011			December 31, 2010
(In millions, except shares)	(unaudited)
ASSETS
Current Assets
Cash and cash equivalents	$	2,711		$	2,951
Funds deposited by counterparties	317			408
Restricted cash	13			8
Accounts receivable — trade, less allowance for doubtful accounts of $17 and $25	687			734
Inventory	418			453
Derivative instruments valuation	1,774			1,964
Cash collateral paid in support of energy risk management activities	147			323
Prepayments and other current assets	311			296
Total current assets	6,378			7,137
Property, plant and equipment, net of accumulated depreciation of $3,987 and $3,796	11,579			12,517
Other Assets
Equity investments in affiliates	521			536
Note receivable — affiliate and capital leases, less current portion	415			384
Goodwill	1,863			1,868
Intangible assets, net of accumulated amortization of $1,154 and $1,064	1,686			1,776
Nuclear decommissioning trust fund	428			412
Derivative instruments valuation	674			758
Restricted cash supporting funded letter of credit facility	1,301			1,300
Other non-current assets	198			208
Total other assets	7,086			7,242
Total Assets	$	25,043		$	26,896
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	150		$	463
Accounts payable	568			783
Derivative instruments valuation	1,411			1,685
Deferred income taxes	137			108
Cash collateral received in support of energy risk management activities	317			408
Accrued expenses and other current liabilities	415			773
Total current liabilities	2,998			4,220
Other Liabilities
Long-term debt and capital leases	8,802			8,748
Funded letter of credit	1,300			1,300
Nuclear decommissioning reserve	322			317
Nuclear decommissioning trust liability	281			272
Deferred income taxes	1,812			1,989
Derivative instruments valuation	335			365
Out-of-market contracts	211			223
Other non-current liabilities	1,133			1,142
Total non-current liabilities	14,196			14,356
Total Liabilities	17,194			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	5,330			5,323
Retained earnings	3,538			3,800
Less treasury stock, at cost — 56,742,955 and 56,808,672 shares, respectively	(1,633		)	(1,503		)
Accumulated other comprehensive income	363			432
Noncontrolling interest	—			17
Total Stockholders’ Equity	7,601			8,072
Total Liabilities and Stockholders’ Equity	$	25,043		$	26,896

See notes to condensed consolidated financial statements.

Table of Contents

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions) Three months ended March 31,	2011			2010
Cash Flows from Operating Activities
Net (loss)/income	$	(260	)	$	58
Adjustments to reconcile net (loss)/income to net cash provided by operating activities:
Distributions and equity in losses/(earnings) of unconsolidated affiliates	9			(5		)
Depreciation and amortization	205			202
Provision for bad debts	8			9
Amortization of nuclear fuel	11			10
Amortization of financing costs and debt discount/premiums	8			8
Amortization of intangibles and out-of-market contracts	48			—
Changes in deferred income taxes and liability for uncertain tax benefits	(109		)	74
Changes in nuclear decommissioning trust liability	10			11
Changes in derivatives	(130		)	24
Changes in collateral deposits supporting energy risk management activities	176			(172		)
Impairment charge on investment	481			—
Cash used by changes in other working capital	(241		)	(105		)
Net Cash Provided by Operating Activities	216			114
Cash Flows from Investing Activities
Capital expenditures	(219		)	(185		)
Increase in restricted cash, net	(5		)	(5		)
Decrease in notes receivable	12			7
Purchases of emission allowances	(7		)	(34		)
Proceeds from sale of emission allowances	3			9
Investments in nuclear decommissioning trust fund securities	(105		)	(78		)
Proceeds from sales of nuclear decommissioning trust fund securities	95			67
Proceeds from sale of assets	13			30
Other	(15		)	(5		)
Net Cash Used by Investing Activities	(228		)	(194		)
Cash Flows from Financing Activities
Payment of dividends to preferred stockholders	(2		)	(2		)
Payment for treasury stock	(130		)	—
Net (payments to)/receipts from acquired derivatives that include financing elements	(17		)	13
Proceeds from issuance of long-term debt	1,286			10
Increase in restricted cash supporting funded letter of credit	(1		)	—
Proceeds from issuance of common stock	1			2
Payment of deferred debt issuance costs	(8		)	(2		)
Payments for short and long-term debt	(1,361		)	(429		)
Net Cash Used by Financing Activities	(232		)	(408		)
Effect of exchange rate changes on cash and cash equivalents	4			(3		)
Net Decrease in Cash and Cash Equivalents	(240		)	(491		)
Cash and Cash Equivalents at Beginning of Period	2,951			2,304
Cash and Cash Equivalents at End of Period	$	2,711		$	1,813

See notes to condensed consolidated financial statements.

Table of Contents

NRG ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 — Basis of Presentation

NRG Energy, Inc., or NRG or the Company, is a wholesale power generation and integrated 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 and carbon offset 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 March 31, 2011, and the results of operations and cash flows for the three months ended March 31, 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 do not include capital expenditures of $62 million which were accrued and unpaid at March 31, 2011.

Table of Contents

Note 3 — Comprehensive (Loss)/Income

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

(In millions) Three months ended March 31,	2011			2010
Net (Loss)/Income attributable to NRG Energy, Inc.	$	(260	)	$	58
Changes in derivative activity	(82		)	257
Foreign currency translation adjustment	12			(6		)
Unrealized gain on available-for-sale securities	1			—
Other comprehensive (loss)/income	$	(69	)	251
Comprehensive (loss)/income attributable to NRG Energy, Inc.	$	(329	)	$	309

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	(82		)
Foreign currency translation adjustment	12
Unrealized gain on available-for-sale securities	1
Accumulated other comprehensive income as of March 31, 2011	$	363

Note 4 — Business Acquisitions and Disposition

2011 Acquisition

On April 5, 2011, NRG acquired a 50.1% stake in the 392 MW Ivanpah Solar Electric Generating System, or the Ivanpah Project, from BrightSource Energy, Inc., or BSE. NRG paid $68 million in cash and committed an additional $70 million of cash and $122 million of availability under its Funded Letter of Credit Facility in connection with the total commitment of up to $300 million. The Ivanpah Project is composed of three separate facilities — Ivanpah 1 (126 MW), Ivanpah 2 (133 MW), and Ivanpah 3 (133 MW), and all three facilities are expected to be fully operational by the end of 2013. The Ivanpah Project has received project financing of $1.6 billion, which is guaranteed by the U.S. Department of Energy, or U.S. DOE. Power generated from the Ivanpah Project will be sold to Southern California Edison and Pacific Gas & Electric, under multiple 20-25 year power purchase agreements, or PPAs. The acquisition will be recorded in the second quarter of 2011 as a business combination under ASC-805, Business Combinations , or ASC 805, and the purchase price will be preliminarily allocated to the assets acquired and liabilities assumed, based on their acquisition-date fair values.

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.

Table of Contents

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 three months ended March 31, 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, including TEPCO’s contingent investment in a wholly-owned subsidiary of NINA through an Investment and Option Agreement signed on May 10, 2010. 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 TANE. 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 expects to incur one-time costs, related to contributions to NINA, which are not expected to exceed $20 million. These costs will be expensed as incurred.

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 $481 million as of March 31, 2011 for the full amount of its investment. This impairment charge includes net assets contributed from all of NINA’s equity investors, both NRG and TANE, which the Company previously consolidated.

Table of Contents

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 has 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 March 31, 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
	March 31, 2011		December 31, 2010		March 31, 2011		December 31, 2010
Assets:	(In millions)
Cash and cash equivalents	$	2,711	$	2,951	$	2,711	$	2,951
Funds deposited by counterparties	317		408		317		408
Restricted cash	13		8		13		8
Cash collateral paid in support of energy risk management activities	147		323		147		323
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities	9		8		9		8
Marketable equity securities	3		3		3		3
Trust fund investments	430		414		430		414
Notes receivable	200		177		194		190
Derivative assets	2,448		2,722		2,448		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	8,841		9,104		9,071		9,236
Funded letter of credit	1,300		1,300		1,292		1,295
Cash collateral received in support of energy risk management activities	317		408		317		408
Derivative liabilities	$	1,746	$	2,050	$	1,746	$	2,050

Table of Contents

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 March 31, 2011	Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	2,711	$	—	$	—	$	2,711
Funds deposited by counterparties	317		—		—		317
Restricted cash	13		—		—		13
Cash collateral paid in support of energy risk management activities	147		—		—		147
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities	—		—		9		9
Marketable equity securities	3		—		—		3
Trust fund investments
Cash and cash equivalents	4		—		—		4
U.S. government and federal agency obligations	31		5		—		36
Federal agency mortgage-backed securities	—		56		—		56
Commercial mortgage-backed securities	—		12		—		12
Corporate debt securities	—		54		—		54
Marketable equity securities	227		—		40		267
Foreign government fixed income securities	—		1		—		1
Derivative assets
Commodity contracts	701		1,692		55		2,448
Restricted cash supporting funded letter of credit facility	1,301		—		—		1,301
Total assets	$	5,455	$	1,820	$	104	$	7,379
Cash collateral received in support of energy risk management activities	$	317	$	—	$	—	$	317
Derivative liabilities
Commodity contracts	666		947		66		1,679
Interest rate contracts	—		67		—		67
Total liabilities	$	983	$	1,014	$	66	$	2,063

Table of Contents

(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 have been no transfers during the three months ended March 31, 2011, and 2010, between Levels 1 and 2. The following tables reconcile, for the three months ended March 31, 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)
(In millions) Three months ended March 31, 2011	Debt Securities		Trust Fund Investments		Derivatives (a)			Total
Beginning balance as of January 1, 2011	$	8	$	39	$	(27	)	$	20
Total gains and losses (realized/unrealized)
Included in earnings	—		—		9			9
Included in OCI	1		—		—			1
Included in nuclear decommissioning obligations	—		1		—			1
Purchases	—		—		3			3
Transfers into Level 3 (b)	—		—		(18		)	(18		)
Transfers out of Level 3 (b)	—		—		22			22
Ending balance as of March 31, 2011	$	9	$	40	$	(11	)	$	38
The amount of the total gains for the period included in earnings attributable to the change in unrealized gains relating to assets still held as of March 31, 2011	$	—	$	—	$	2		$	2

Table of Contents

	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
(In millions) Three months ended March 31, 2010	Debt Securities		Trust Fund Investments		Derivatives (a)			Total
Beginning balance as of January 1, 2010	$	9	$	37	$	(13	)	$	33
Total gains and losses (realized/unrealized)
Included in earnings	—		—		32			32
Purchases	—		—		1			1
Transfers into Level 3 (b)	—		—		(62		)	(62		)
Transfers out of Level 3 (b)	—		—		17			17
Ending balance as of March 31, 2010	$	9	$	37	$	(25	)	$	21
The amount of the total gains for the period included in earnings attributable to the change in unrealized gains relating to assets still held as of March 31, 2010	$	—	$	—	$	25		$	25

(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 transfer 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 March 31, 2011, the credit reserve resulted in a $1 million decrease in fair value which is composed of a $1 million gain in OCI and a $2 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 financial instruments. Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. NRG is exposed to counterparty credit risk through various activities including wholesale sales, fuel purchases and retail supply and retail customer credit risk through its retail load activities.

Counterparty Credit Risk

The Company monitors and manages 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.

Table of Contents

As of March 31, 2011, counterparty credit exposure to a significant portion of the Company’s counterparties was $1.2 billion and NRG held collateral (cash and letters of credit) against those positions of $322 million, resulting in a net exposure of $920 million. 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	54	%
Utilities, energy, merchants, marketers and other	40
Coal and emissions	3
ISOs	3
Total as of March 31, 2011	100	%

	Net Exposure (a)
Category	(% of Total)
Investment grade	72	%
Non-Investment grade	3
Non-rated (b)	25
Total as of March 31, 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 $248 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 March 31, 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 March 31, 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 with government entities.

Table of Contents

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 the decommissioning of 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 March 31, 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	$	4	$	—	$	—	—	$	9	$	—	$	—	—
U.S. government and federal agency obligations	29		1		—		9	25		1		—		9
Federal agency mortgage-backed securities	61		2		—		23	57		2		—		24
Commercial mortgage-backed securities	12		—		—		29	11		—		—		29
Corporate debt securities	54		2		1		11	56		3		1		10
Marketable equity securities	267		130		1		—	252		117		1		—
Foreign government fixed income securities	1		—		—		15	2		—		—		8
Total	$	428	$	135	$	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.

	Three months ended March 31,
(In millions)	2011		2010
Realized gains	$	2	$	1
Realized losses	2		1
Proceeds from sale of securities	95		67

Table of Contents

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 March 31, 2011, NRG had energy-related derivative financial instruments extending through April 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 March 31, 2011, NRG had interest rate derivative instruments on recourse debt extending through 2013 and on non-recourse debt extending through 2028, 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 March 31, 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
		March 31, 2011			December 31, 2010
Commodity	Units	(In millions)
Coal	Short Ton	29			34
Natural Gas	MMBtu	(117		)	(175		)
Oil	Barrel	1			1
Power	MWh	10			5
Capacity	MW/Day	—			(1		)
Interest	Dollars	$	1,232		$	2,782

Table of Contents

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)	March 31, 2011		December 31, 2010		March 31, 2011		December 31, 2010
Derivatives Designated as Cash Flow or Fair Value Hedges :
Interest rate contracts current	$	—	$	—	$	—	$	17
Interest rate contracts long-term	—		—		67		71
Commodity contracts current	347		392		10		2
Commodity contracts long-term	164		217		2		—
Total Derivatives Designated as Cash Flow or Fair Value Hedges	511		609		79		90
Derivatives Not Designated as Cash Flow or Fair Value Hedges :
Commodity contracts current	1,427		1,572		1,401		1,666
Commodity contracts long-term	510		541		266		294
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges	1,937		2,113		1,667		1,960
Total Derivatives	$	2,448	$	2,722	$	1,746	$	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 March 31,
	2011									2010
(In millions)	Energy Commodities			Interest Rate			Total			Energy Commodities			Interest Rate			Total
Accumulated OCI beginning balance	$	488		$	(47	)	$	441		$	461		$	(55	)	$	406
Reclassified from accumulated OCI to income:
- Due to realization of previously deferred amounts	(98		)	11			(87		)	(106		)	2			(104		)
Mark-to-market of cash flow hedge accounting contracts	2			3			5			364			(3		)	361
Accumulated OCI ending balance, net of $220 and $398 tax, respectively	$	392		$	(33	)	$	359		$	719		$	(56	)	$	663
Gains/(losses) expected to be realized from OCI during the next 12 months, net of $154 and $228 tax, respectively	$	265		$	(2	)	$	263		$	432		$	(43	)	$	389
Gains/(losses) recognized in income from the ineffective portion of cash flow hedges	$	3		$	(1	)	$	2		$	(2	)	$	—		$	(2	)

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 March 31,
(In millions)	2011		2010
Derivative	$	—	$	3
Senior Notes (hedged item)	—		(3		)

Table of Contents

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/(losses) are included within operating revenues and cost of operations.

	Three months ended March 31,
(In millions)	2011			2010
Unrealized mark-to-market results
Reversal of previously recognized unrealized gains on settled positions related to economic hedges	$	(2	)	$	(40	)
Reversal of loss positions acquired as part of the Reliant Energy acquisition as of May 1, 2009	28			90
Reversal of loss positions acquired as part of the Green Mountain Energy acquisition as of November 5, 2010	13			—
Reversal of previously recognized unrealized losses on settled positions related to trading activity	14			18
Net unrealized gains/(losses) on open positions related to economic hedges	91			(118		)
Gains/(losses) on ineffectiveness associated with open positions treated as cash flow hedges	3			(2		)
Net unrealized gains on open positions related to trading activity	—			14
Total unrealized gains/(losses)	$	147		$	(38	)

	Three months ended March 31,
(In millions)	2011		2010
Revenue from operations - energy commodities	$	13	$	69
Cost of operations	134		(107		)
Total impact to statement of operations	$	147	$	(38	)

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 three months ended March 31, 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 an increase in forward power and gas prices.

For the three months ended March 31, 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.

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 March 31, 2011, was $59 million. The collateral required for contracts with credit rating contingent features was $18 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 $5 million as of March 31, 2011.

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

Table of Contents

Note 9 — Long-Term Debt

Prepayment on 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.

Redemption of 2014 Senior Notes

On January 11, 2011, the Company announced a tender offer on the 2014 Senior Notes and on January 26, 2011, the Company redeemed $945 million of the 2014 Senior Notes 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 was 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 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. As of March 31, 2011, $1.2 billion in principal was outstanding under the 2018 Senior Notes.

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%.

Indian River Power LLC Tax-Exempt Bonds

During the first quarter 2011, the Company received $29 million in additional proceeds from the Delaware Economic Development Authority tax-exempt bond financing, and $37 million in additional proceeds related to the Sussex County, Delaware tax-exempt bond financing, bringing the total proceeds received on these bonds to $133 million as of March 31, 2011.

Table of Contents

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 $92 million as of March 31, 2011.

GenConn Energy LLC — Through its subsidiary, NRG Connecticut Peaking, 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. The Middletown project is in the advanced stages of construction, with a target commercial operation date of June 2011.

NRG Connecticut Peaking had a note receivable due from GenConn for $63 million as of March 31, 2011 as discussed in Note 9, Capital Leases and Notes Receivable to the Company’s 2010 Form 10-K. As of March 31, 2011, NRG had a $65 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 March 31, 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	55,496	—		55,496
Shares issued under ESPP	—	65,717		65,717
Balance as of March 31, 2011	304,061,523	(56,742,955	)	247,318,568

2011 Capital Allocation Plan

As part of the Company’s 2011 Capital 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 ASR Agreement was accounted for as a forward contract indexed to the Company’s own stock and recorded as treasury stock on February 25, 2011. 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.

Table of Contents

Note 12 — (Loss)/Earnings Per Share

Basic (loss)/earnings per common share is computed by dividing net (loss)/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 (loss)/earnings per share is computed in a manner consistent with that of basic (loss)/earnings per share while giving effect to all potentially dilutive common shares that were outstanding during the period. Shares borrowed under the Share Lending Agreement (see Note 15, Capital Structure — Share Lending Agreements in the Company’s Form 2010 10-K) were not treated as outstanding for earnings per share purposes.

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

	Three months ended March 31,
(In millions, except per share data)	2011			2010
*Basic (loss)/earnings per share attributable to NRG common stockholders*
Numerator:
Net (loss)/income attributable to NRG Energy, Inc.	$	(260	)	$	58
Preferred stock dividends	(2		)	(2		)
Net (loss)/income attributable to NRG Energy, Inc. available to common stockholders	$	(262	)	$	56
Denominator:
Weighted average number of common shares outstanding	247			254
*Basic (loss)/earnings per share:*
Net (loss)/income attributable to NRG Energy, Inc.	$	(1.06	)	$	0.22
*Diluted (loss)/earnings per share attributable to NRG common stockholders*
Numerator:
Net (loss)/income attributable to NRG Energy, Inc. available to common stockholders	$	(262	)	$	56
Denominator:
Weighted average number of common shares outstanding	247			254
Incremental shares attributable to the issuance of equity compensation (treasury stock method)	—			1
Incremental shares attributable to assumed conversion features of outstanding preferred stock (if-converted method)	—			2
Total dilutive shares	247			257
*Diluted (loss)/earnings per share:*
Net (loss)/income attributable to NRG Energy, Inc.	$	(1.06	)	$	0.22

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

	Three months ended March 31,
(In millions of shares)	2011	2010
Equity compensation — NQSOs and PUs	7	6
Embedded derivative of 3.625% redeemable perpetual preferred stock	16	16
Total	23	22

Table of Contents

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, wind and nuclear development, as well as 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 March 31, 2011	Reliant Energy		Texas (a)			Northeast			South Central		West		International		Thermal		Corporate (b) (c)			Elimination			Total
Operating revenues	$	1,005	$	531		$	226		$	189	$	42	$	35	$	40	$	122		$	(195	)	$	1,995
Depreciation and amortization	24		122			29			20		3		—		3		4			—			205
Equity in (losses)/earnings of unconsolidated affiliates	—		(8		)	2			—		—		4		—		—			—			(2		)
Income/(loss) before income taxes	272		7			(32		)	14		13		10		5		(654		)	—			(365		)
Net income/(loss) attributable to NRG Energy, Inc.	$	272	$	7		$	(32	)	$	14	$	13	$	8	$	5	$	(547	)	$	—		$	(260	)
Total assets	$	1,484	$	12,942		$	1,904		$	1,309	$	530	$	779	$	333	$	19,340		$	(13,578	)	$	25,043

(a) Includes inter-segment sales of $168 million to Reliant Energy and $25 million to Green Mountain Energy.

(b) Includes Green Mountain Energy results.

(In millions)				Wholesale Power Generation
Three months ended March 31, 2010	Reliant Energy			Texas (d)		Northeast		South Central			West		International		Thermal		Corporate			Elimination			Total
Operating revenues	$	1,176		$	870	$	279	$	143		$	35	$	35	$	36	$	2		$	(361	)	$	2,215
Depreciation and amortization	30			117		32		16			3		—		2		2			—			202
Equity in earnings of unconsolidated affiliates	—			10		—		—			—		4		—		—			—			14
(Loss)/income before income taxes	(188		)	375		52		(4		)	6		10		4		(132		)	—			123
Net (loss)/income attributable to NRG Energy, Inc.	$	(188	)	$	375	$	52	$	(4	)	$	6	$	8	$	4	$	(195	)	$	—		$	58

(d) Includes inter-segment sales of $360 million with Reliant Energy.

Table of Contents

Note 14 — Income Taxes

Effective Tax Rate

The income tax provision consisted of the following:

	Three months ended March 31,
(In millions, except otherwise noted)	2011			2010
Income tax (benefit)/expense	$	(105	)	$	65
Effective tax rate	28.8		%	52.7		%

For the three months ended March 31, 2011, NRG recorded an income tax benefit as a result of a pre-tax loss of $365 million. NRG’s overall effective tax rate was different than the statutory rate of 35% primarily due to the change in the valuation allowance resulting from capital losses generated in the quarter for which there were no projected capital gains or available tax planning strategies. For the three months ended March 31, 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 March 31, 2011, NRG has recorded a non-current tax liability of $583 million for uncertain tax benefits resulting from taxable earnings for the period for which there are no net operating losses available to offset for financial statement purposes. NRG has accrued interest and penalties related to these uncertain tax benefits of $4 million for the three months ended March 31, 2011, and has accrued $46 million since adoption. The Company recognizes interest and penalties related to uncertain tax benefits in income tax expense.

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

Tax Receivable and Payable

As of March 31, 2011, NRG recorded a current tax payable of $36 million that represents a tax liability due for domestic state taxes of $27 million, as well as foreign taxes payable of $9 million. In addition, as of March 31, 2011, NRG has a domestic tax receivable of $77 million, of which $69 million is related to property tax refunds primarily 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 three months ended March 31, 2011, including reimbursements to STPNOC, was $10 million. NRG expects to make approximately $13 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 $10 million and $8 million for the three months ended March 31, 2011, and 2010, respectively.

Table of Contents

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 March 31, 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.

Table of Contents

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.

Table of Contents

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.

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.

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

Table of Contents

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). The Company has established an appropriate reserve. On February 28, 2011, FERC issued an order denying rehearing. The Company, together with other generators, is planning to file an appeal.

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.

Table of Contents

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.

Table of Contents

Note 18 — Environmental Matters

The construction and operation of power projects are subject to stringent environmental and safety protection and land use laws and regulation in the U.S. If such laws and regulations become more stringent, or new laws, interpretations or compliance policies apply and NRG’s facilities are not exempt from coverage, the Company could be required to make modifications to further reduce potential environmental impacts. In general, the effect of such future laws or regulations is expected to require the addition of pollution control equipment or the imposition of restrictions or additional costs on the Company’s operations.

Environmental Capital Expenditures

Based on current rules, technology and plans, NRG has estimated that environmental capital expenditures from 2011 through 2015 to meet NRG’s environmental commitments will be approximately $721 million and are primarily associated with controls on the Company’s Big Cajun and Indian River facilities. These capital expenditures, in general, are related to installation of particulate, SO 2 , NO x , and mercury controls to comply with federal and state air quality rules and consent orders, as well as mitigation for once through cooling. NRG continues to explore cost effective compliance alternatives. This estimate reflects anticipated schedules and controls related to CAIR, the proposed CATR, the proposed Mercury and Air Toxics Standards, and the proposed 316(b) Rule. Until the rules are final, the full impact on the scope and timing of environmental retrofits from any new or revised regulations cannot be determined.

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.

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.

Table of Contents

Note 19 — Condensed Consolidating Financial Information

As of March 31, 2011, the Company had outstanding $2.4 billion of 7.375% Senior Notes due 2016, $1.1 billion of 7.375% Senior Notes due 2017, $700 million of 8.50% Senior Notes due 2019, $1.2 billion of 7.625% Senior Notes due 2018, and $1.1 billion of 8.25% Senior Notes due 2020. These notes are guaranteed by certain of NRG’s current and future wholly-owned domestic subsidiaries, or guarantor subsidiaries.

Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of March 31, 2011:

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

Table of Contents

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.

Table of Contents

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Three Months Ended March 31, 2011

(In millions)	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations (a)			Consolidated Balance
Operating Revenues
Total operating revenues	$	1,904		$	104		$	—		$	(13	)	$	1,995
Operating Costs and Expenses
Cost of operations	1,253			72			5			(6		)	1,324
Depreciation and amortization	192			10			3			—			205
Selling, general and administrative	81			5			57			—			143
Development costs	—			(1		)	10			—			9
Total operating costs and expenses	1,526			86			75			(6		)	1,681
Operating Income/(Loss)	378			18			(75		)	(7		)	314
Other Income/(Expense)
Equity in earnings/(losses) of consolidated subsidiaries	9			(1		)	(78		)	70			—
Equity in losses of unconsolidated affiliates	—			(2		)	—			—			(2		)
Impairment charge on investment	(481		)	—			—			—			(481		)
Other income, net	—			4			1			—			5
Loss on debt extinguishment	—			—			(28		)	—			(28		)
Interest expense	(9		)	(13		)	(151		)	—			(173		)
Total other (expense)/ income	(481		)	(12		)	(256		)	70			(679		)
(Loss)/Income Before Income Taxes	(103		)	6			(331		)	63			(365		)
Income tax (benefit)/expense	(36		)	2			(71		)	—			(105		)
Net (Loss)/Income attributable to NRG Energy, Inc.	$	(67	)	$	4		$	(260	)	$	63		$	(260	)

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

Table of Contents

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

March 31, 2011

(In millions)	Guarantor Subsidiaries		Non- Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations (a)			Consolidated Balance
ASSETS
Current Assets
Cash and cash equivalents	$	84	$	133		$	2,494		$	—		$	2,711
Funds deposited by counterparties	317		—			—			—			317
Restricted cash	2		11			—			—			13
Accounts receivable, net	648		39			—			—			687
Inventory	410		8			—			—			418
Derivative instruments valuation	1,774		—			—			—			1,774
Cash collateral paid in support of energy risk management activities	145		2			—			—			147
Prepayments and other current assets	140		50			1,295			(1,174		)	311
Total current assets	3,520		243			3,789			(1,174		)	6,378
Net property, plant and equipment	10,743		803			49			(16		)	11,579
Other Assets
Investment in subsidiaries	711		168			13,282			(14,161		)	—
Equity investments in affiliates	46		475			—			—			521
Notes receivable — affiliate and capital leases, less current portion	—		415			794			(794		)	415
Goodwill	1,863		—			—			—			1,863
Intangible assets, net	1,627		65			32			(38		)	1,686
Nuclear decommissioning trust fund	428		—			—			—			428
Derivative instruments valuation	674		—			—			—			674
Restricted cash supporting funded letter of credit facility	—		1,301			—			—			1,301
Other non-current assets	45		18			135			—			198
Total other assets	5,394		2,442			14,243			(14,993		)	7,086
Total Assets	$	19,657	$	3,488		$	18,081		$	(16,183	)	$	25,043
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	1,149	$	124		$	26		$	(1,149	)	$	150
Accounts payable	324		45			199			—			568
Derivative instruments valuation	1,409		2			—			—			1,411
Deferred income taxes	691		(51		)	(503		)	—			137
Cash collateral received in support of energy risk management activities	317		—			—			—			317
Accrued expenses and other current liabilities	353		30			56			(24		)	415
Total current liabilities	4,243		150			(222		)	(1,173		)	2,998
Other Liabilities
Long-term debt and capital leases	482		1,045			8,069			(794		)	8,802
Funded letter of credit	—		—			1,300			—			1,300
Nuclear decommissioning reserve	322		—			—			—			322
Nuclear decommissioning trust liability	281		—			—			—			281
Deferred income taxes	1,113		276			423			—			1,812
Derivative instruments valuation	267		30			38			—			335
Out-of-market contracts	235		7			—			(31		)	211
Other non-current liabilities	487		22			624			—			1,133
Total non-current liabilities	3,187		1,380			10,454			(825		)	14,196
Total liabilities	7,430		1,530			10,232			(1,998		)	17,194
3.625% Preferred Stock	—		—			248			—			248
Stockholders’ Equity	12,227		1,958			7,601			(14,185		)	7,601
Total Liabilities and Stockholders’ Equity	$	19,657	$	3,488		$	18,081		$	(16,183	)	$	25,043

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

Table of Contents

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2011

(In millions)	Guarantor Subsidiaries			Non- Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations (a)			Consolidated Balance
Cash Flows from Operating Activities
Net (loss)/income	$	(67	)	$	4		$	(260	)	$	63		$	(260	)
Adjustments to reconcile net income/(loss) to net cash (used)/provided by operating activities:
Distributions and equity in (earnings)/losses of unconsolidated affiliates and consolidated subsidiaries	(9		)	10			78			(70		)	9
Depreciation and amortization	192			10			3			—			205
Provision for bad debts	8			—			—			—			8
Amortization of nuclear fuel	11			—			—			—			11
Amortization of financing costs and debt discount/premiums	—			1			7			—			8
Amortization of intangibles and out-of-market contracts	48			—			—			—			48
Changes in deferred income taxes and liability for uncertain tax benefits	(145		)	(14		)	50			—			(109		)
Changes in nuclear decommissioning trust liability	10			—			—			—			10
Changes in derivatives	(130		)	—			—			—			(130		)
Changes in collateral deposits supporting energy risk management activities	176			—			—			—			176
Impairment charge on investment	481			—			—			—			481
Cash (used)/provided by changes in other working capital	46			2			(296		)	7			(241		)
Net Cash Provided/(Used) by Operating Activities	621			13			(418		)	—			216
Cash Flows from Investing Activities
Intercompany loans to subsidiaries	(705		)	(13		)	(158		)	876			—
Capital expenditures	(86		)	(115		)	(18		)	—			(219		)
Increase in restricted cash, net	—			(5		)	—			—			(5		)
Decrease in notes receivable	—			12			—			—			12
Purchases of emission allowances	(7		)	—			—			—			(7		)
Proceeds from sale of emission allowances	3			—			—			—			3
Investments in nuclear decommissioning trust fund securities	(105		)	—			—			—			(105		)
Proceeds from sales of nuclear decommissioning trust fund securities	95			—			—			—			95
Proceeds from sale of assets	13			—			—			—			13
Other	—			(5		)	(10		)	—			(15		)
Net Cash Used by Investing Activities	(792		)	(126		)	(186		)	876			(228		)
Cash Flows from Financing Activities
Proceeds from intercompany loans	38			120			718			(876		)	—
Payment of dividends to preferred stockholders	—			—			(2		)	—			(2		)
Payment for treasury stock	—			—			(130		)	—			(130		)
Net payments to settle acquired derivatives that include financing elements	(17		)	—			—			—			(17		)
Proceeds from issuance of long-term debt	66			20			1,200			—			1,286
Increase in restricted cash supporting funded letter of credit	—			(1		)	—			—			(1		)
Proceeds from issuance of common stock	—			—			1			—			1
Payment of deferred debt issuance costs	—			(2		)	(6		)	—			(8		)
Payments for short and long-term debt	—			(6		)	(1,355		)	—			(1,361		)
Net Cash Provided/(Used) by Financing Activities	87			131			426			(876		)	(232		)
Effect of exchange rate changes on cash and cash equivalents	—			4			—			—			4
Net (Decrease)/Increase in Cash and Cash Equivalents	(84		)	22			(178		)	—			(240		)
Cash and Cash Equivalents at Beginning of Period	168			111			2,672			—			2,951
Cash and Cash Equivalents at End of Period	$	84		$	133		$	2,494		$	—		$	2,711

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

Table of Contents

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Three Months Ended March 31, 2010

(In millions)	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations (a)			Consolidated Balance
Operating Revenues
Total operating revenues	$	2,127		$	95		$	—		$	(7	)	$	2,215
Operating Costs and Expenses
Cost of operations	1,573			66			7			(7		)	1,639
Depreciation and amortization	190			10			2			—			202
Selling, general and administrative	67			3			60			—			130
Development costs	—			3			6			—			9
Total operating costs and expenses	1,830			82			75			(7		)	1,980
Gain on sale of assets	—			—			23			—			23
Operating Income/(Loss)	297			13			(52		)	—			258
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries	7			—			194			(201		)	—
Equity in earnings of unconsolidated affiliates	—			14			—			—			14
Other income, net	1			3			—			—			4
Interest expense	(5		)	(14		)	(134		)	—			(153		)
Total other income/(expense)	3			3			60			(201		)	(135		)
Income Before Income Taxes	300			16			8			(201		)	123
Income tax expense/(benefit)	111			4			(50		)	—			65
Net Income attributable to NRG Energy, Inc.	$	189		$	12		$	58		$	(201	)	$	58

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

Table of Contents

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.

Table of Contents

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2010

(In millions)	Guarantor Subsidiaries			Non- Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations (a)			Consolidated Balance
Cash Flows from Operating Activities
Net income	$	189		$	12		$	58		$	(201	)	$	58
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	(7		)	(5		)	(194		)	201			(5		)
Depreciation and amortization	190			10			2			—			202
Provision for bad debts	9			—			—			—			9
Amortization of nuclear fuel	10			—			—			—			10
Amortization of financing costs and debt discount/premiums	—			2			6			—			8
Changes in deferred income taxes and liability for uncertain tax benefits	111			2			(39		)	—			74
Changes in nuclear decommissioning trust liability	11			—			—			—			11
Changes in derivatives	22			2			—			—			24
Changes in collateral deposits supporting energy risk management activities	(172		)	—			—			—			(172		)
Cash (used)/provided by changes in other working capital	(105		)	(63		)	63			—			(105		)
Net Cash Provided/(Used) by Operating Activities	258			(40		)	(104		)	—			114
Cash Flows from Investing Activities
Intercompany loans to subsidiaries	(178		)	—			(32		)	210			—
Investment in subsidiaries	—			328			(328		)	—			—
Capital expenditures	(99		)	(73		)	(13		)	—			(185		)
Increase in restricted cash, net	—			(5		)	—			—			(5		)
Decrease in notes receivable	—			7			—			—			7
Purchases of emission allowances	(34		)	—			—			—			(34		)
Proceeds from sale of emission allowances	9			—			—			—			9
Investments in nuclear decommissioning trust fund securities	(78		)	—			—			—			(78		)
Proceeds from sales of nuclear decommissioning trust fund securities	67			—			—			—			67
Proceeds from sale of assets	1			—			29			—			30
Other	—			—			(5		)	—			(5		)
Net Cash (Used)/Provided by Investing Activities	(312		)	257			(349		)	210			(194		)
Cash Flows from Financing Activities
Proceeds from intercompany loans	31			1			178			(210		)	—
Payment of dividends to preferred stockholders	—			—			(2		)	—			(2		)
Net receipt from acquired derivatives that include financing elements	13			—			—			—			13
Proceeds from issuance of long-term debt	3			7			—			—			10
Proceeds from issuance of common stock	—			—			2			—			2
Payment of deferred debt issuance costs	—			(2		)	—			—			(2		)
Payments for short and long-term debt	—			(193		)	(236		)	—			(429		)
Net Cash Provided/(Used) by Financing Activities	47			(187		)	(58		)	(210		)	(408		)
Effect of exchange rate changes on cash and cash equivalents	—			(3		)	—			—			(3		)
Net (Decrease)/Increase in Cash and Cash Equivalents	(7		)	27			(511		)	—			(491		)
Cash and Cash Equivalents at Beginning of Period	20			120			2,164			—			2,304
Cash and Cash Equivalents at End of Period	$	13		$	147		$	1,653		$	—		$	1,813

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

Table of Contents

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 months ended March 31, 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.

Table of Contents

Executive Summary

Introduction and Overview

As of March 31, 2011, NRG had a total global generation portfolio of 193 active operating fossil fuel and nuclear generation units, at 45 power generation plants, with an aggregate generation capacity of approximately 24,570 MW, and approximately 815 MW under construction which includes partner interests of 120 MW. In addition to its fossil fuel plant ownership, NRG has ownership interests in operating renewable facilities with an aggregate generation capacity of 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 23,565 MW of fossil fuel and nuclear generation capacity in 185 active generating units at 43 plants. The Company’s power generation facilities are most heavily concentrated in Texas (approximately 10,745 MW, including 450 MW from four wind farms), the Northeast (approximately 6,900 MW), South Central (approximately 4,125 MW), and West (approximately 2,150 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 46%, 31%, 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 March 31, 2011, Reliant Energy and Green Mountain Energy combined 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.

Table of Contents

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 our 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 of 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: CAIR/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 CAIR Phase I and II, CATR, MACT standards for mercury and air toxics, and the installation of Best Technology Available, or 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.

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 and associated costs 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. NRG expects to comply with these requirements with a mix of intake and operational modifications.

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

Table of Contents

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 directed FERC staff to convene a technical conference to expeditiously explore issues related to the pricing of the CPM.

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.

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, the 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. Requests for rehearing have been submitted by numerous parties and compliance filings are pending and being contested.

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.

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 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.

Following the earthquake and tsunami that impacted Japan on March 11, 2011, the NRC commenced a systematic review of policies, practices, and equipment performance related to domestic nuclear units. The NRC may make recommendations for improvements that relate to or otherwise affect STP Units 1 & 2.

Changes in Accounting Standards

None.

Table of Contents

Consolidated Results of Operations

The following table provides selected financial information for NRG Energy, Inc. for the three months ended March 31, 2011, and 2010:

	Three months ended March 31,
(In millions except otherwise noted)	2011			2010			Change %
Operating Revenues
Energy revenue (a)	$	598		$	698		(14	)%
Capacity revenue (a)	185			209			(11	)
Retail revenue	1,180			1,245			(5	)
Mark-to-market activities	13			69			(81	)
Other revenues	19			(6		)	417
Total operating revenues	1,995			2,215			(10	)
Operating Costs and Expenses
Generation cost of sales (a)	551			484			14
Retail cost of sales (a)	609			727			(16	)
Mark-to-market activities	(134		)	107			(225	)
Other cost of operations	298			321			(7	)
Total cost of operations	1,324			1,639			(19	)
Depreciation and amortization	205			202			1
Selling, general and administrative	143			130			10
Development costs	9			9			—
Total operating costs and expenses	1,681			1,980			(15	)
Gain on sale of assets	—			23			(100	)
Operating Income	314			258			22
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates	(2		)	14			(114	)
Impairment charge on investment	(481		)	—			N/A
Other income, net	5			4			25
Loss on debt extinguishment	(28		)	—			N/A
Interest expense	(173		)	(153		)	13
Total other expenses	(679		)	(135		)	403
(Loss)/Income before income tax expense	(365		)	123			(397	)
Income tax (benefit)/expense	(105		)	65			(262	)
Net (Loss)/Income attributable to NRG Energy, Inc.	$	(260	)	$	58		N/A
Business Metrics
Average natural gas price - Henry Hub ($/MMBtu)	4.11			5.30			(22	)%

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

N/A — Not applicable

Table of Contents

Management’s discussion of the results of operations for the three months ended March 31, 2011, and 2010

(Loss)/Income before income tax expense — The pre-tax loss of $365 million for the three months ended March 31, 2011, compared to income of $123 million for the three months ended March 31, 2010, reflects a $481 million loss on the impairment of NRG’s investment in NINA and a $28 million loss on the extinguishment of the 2014 Senior Notes. These losses were offset in part by a net increase year over year in mark-to-market activities, with a net gain of $147 million for the three months ended March 31, 2011, as compared to a net loss of $38 million for the same period in 2010.

Wholesale Power Generation

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

	Three months ended March 31, 2011
(In millions except otherwise noted)	Texas		Northeast		South Central		West		Other		Total Wholesale Power Generation		Eliminations			Consolidated Total

Energy revenue	$	598	$	151	$	112	$	6	$	14	$	881	$	(283	)	$	598

Capacity revenue	5		74		61		29		18		187		(2		)	185

Generation cost of sales	255		145		121		2		28		551		—			551

Business Metrics
MWh sold (in thousands)	11,357		2,592		3,846		34
MWh generated (in thousands)	10,660		2,032		3,997		34
Average on-peak market power prices ($/MWh)	$	50.46	$	57.91	$	35.23	$	35.36

	Three months ended March 31, 2010
(In millions except otherwise noted)	Texas		Northeast		South Central		West		Other		Total Wholesale Power Generation		Eliminations			Consolidated Total

Energy revenue	$	638	$	154	$	94	$	8	$	13	$	907	$	(209	)	$	698

Capacity revenue	7		104		57		26		19		213		(4		)	209

Generation cost of sales	246		98		108		5		27		484		—			484

Business Metrics
MWh sold (in thousands)	10,879		2,389		3,178		69
MWh generated (in thousands)	10,426		2,389		2,642		69
Average on-peak market power prices ($/MWh)	$	41.86	$	52.87	$	43.31	$	47.88

	Three months ended March 31,
Weather Metrics	Texas	Northeast	South Central	West
2011
CDDs (a)	137	—	9	2
HDDs (a)	1,108	3,169	1,866	1,481
2010
CDDs	22	—	—	—
HDDs	1,385	2,853	2,241	1,330
30 year average
CDDs	94	—	31	7
HDDs	1,122	3,094	1,895	1,419

(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.

Table of Contents

· Energy revenue — de creased $100 million, on a consolidated basis, during the three months ended March 31, 2011, compared to the same period in 2010. Including intercompany sales to Reliant Energy, energy revenue for Wholesale Power Generation decreased $26 million, due to:

o Texas — decreased by $40 million with a $67 million decrease driven by a decrease in average realized energy prices of 10%, partially offset by an increase in generation sold of $27 million driven by a decrease in planned outages.

o Northeast — decreased by $3 million, due to a decrease of $45 million in merchant revenue from a decrease in generation of $23 million, or 15%, and a decrease in realized energy prices of $22 million, or 17%. The decreased generation was primarily due to a 25% decrease in coal plant generation, which was attributable to weaker economic conditions in western New York and PJM as well as forced outages in the PJM market, and was offset in part by an increase in oil and gas plant generation attributable to higher reliability run hours at the Arthur Kill plant due to local transmission outages. The decrease in merchant revenue was offset in part by an increase in contract revenues of $45 million from new load-serving contracts.

These decreases were offset by:

o South Central — increased by $18 million due to a $12 million increase in merchant revenue and a $6 million increase in contract revenue. The increase in merchant revenue was driven by an increase in generation sold of 79%, or $23 million, because of two additional Cottonwood units used to satisfy merchant sales, and offset in part by an $11 million, or 22%, decline in average realized prices. The increase in contract revenue was driven by new contracts with three regional municipalities that generated an additional $11 million in revenue, offset by lower volumes and fuel pass-through from the region’s cooperative customers.

· Capacity revenue — decreased $24 million, on a consolidated basis, during the three months ended March 31, 2011, compared to the same period in 2010. Including intercompany sales, capacity revenue for Wholesale Power Generation decreased by $26 million, due to:

o Northeast — decreased by $30 million, of which $10 million is due to the expiration of the Reliability Must-Run, or RMR, contracts for the Montville, Middletown and Norwalk plants on May 31, 2010. Locational Forward Reserve Market, or LFRM, revenues were also down $9 million, due to an 82% decrease in LFRM prices, net of Forward Capacity Market, or FCM, amounts, and a 20% decrease in capacity sold. In addition, the volume of sales under the remaining contracts decreased by 6%, primarily due to higher forced outage rates, and a decrease in prices of $14 million, or 12%, from the same period in 2010.

This decrease was offset by:

o South Central — increased by $4 million primarily due to contributions from the Rockford plants located in the PJM market.

o West — increased by $3 million primarily due to additional capacity sales at El Segundo and a price increase on the Encina tolling agreement as compared to the same period in 2010.

· Generation cost of sales — in creased $67 million during the three months ended March 31, 2011, compared to the same period in 2010 due to:

o Texas — increased by $9 million primarily due to higher coal costs of $18 million and an increase of $9 million in costs of purchased energy, offset by lower natural gas costs of $9 million and lower ancillary services costs of $12 million. Coal costs increased primarily due to higher transportation charges and purchased energy costs reflect increased obligations when baseload plants are unavailable and additional purchases under toll energy agreements. Natural gas costs decreased due to a decrease in average natural gas prices of 19% and a decrease of 14% in gas-fired generation.

Table of Contents

o Northeast — increased by $47 million driven by a $14 million increase in natural gas and oil costs and a $48 million increase in purchased energy, offset in part by a $14 million decrease in coal costs. Natural gas and oil costs increased due to higher generation and purchased energy increased due to costs to supply new load contracts which commenced on June 1, 2010. Coal costs decreased due to a 25% decrease in coal generation related to decreased run times in 2011 offset partially by 7% higher average prices.

o South Central — increased by $13 million due primarily to an increase in natural gas costs of $36 million, offset by a decrease of $32 million in purchased energy costs, as Cottonwood was an owned facility in 2011 as a result of the 2010 acquisition. In addition, coal costs increased by $8 million due to a 10% increase in generation and a 3% increase in coal prices.

These increases were offset by:

o West — decreased by $3 million primarily due to a 50% decrease in natural gas consumption.

Table of Contents

Retail Revenues and Cost of Sales

The Company’s retail revenues and 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.

Reliant Energy

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

Selected Income Statement Data

	Three months ended March 31,
(In millions, except otherwise noted)	2011		2010
Operating Revenues
Mass revenues	$	608	$	713
Commercial and Industrial revenues	412		489
Supply management revenues	29		43
Total retail operating revenues (a)	1,049		1,245
Retail cost of sales (b)	795		952
Total retail gross margin	$	254	$	293

Business Metrics
Electricity sales volume — GWh
Mass	4,635		4,814
Commercial and Industrial (a)	5,691		6,209

Average retail customers count (in thousands, metered locations)
Mass	1,467		1,521
Commercial and Industrial (a)	60		64

Retail customers count (in thousands, metered locations)
Mass	1,470		1,520
Commercial and Industrial (a)	60		64
Weather Metrics
CDDs (c)	151		17
HDDs (c)	960		1,242

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

(b) Includes intercompany purchases from the Texas region of $261 million and $225 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 $39 million for the three months ended March 31, 2011, compared to the same period in 2010. Excluding the estimated favorable impact of $27 million in 2010, for the termination of out-of-market supply contracts in conjunction with the 2009 CSRA unwind, the decrease was due primarily to 6% lower volumes sold, which was driven by fewer Mass customers and lower margins in 2011 on comparable weather-related volumes sold, partially offset by higher Commercial and Industrial margins. Competition and lower unit margins on acquisitions and renewals could drive lower gross margin in the future.

Table of Contents

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

	Three months ended March 31,
(In millions)	2011			2010
Total Retail gross margin	$	254		$	293
Mark-to-market results on energy supply derivatives	184			(288		)
Contract amortization, net	(38		)	(59		)
Other operating expenses	(103		)	(103		)
Depreciation and amortization	(24		)	(30		)
Operating Income/(Loss)	$	273		$	(187	)

· Retail operating revenues — decreased by $196 million for the three months ended March 31, 2011, as compared to the same period in 2010. Excluding supply management revenues, Mass and commercial and industrial revenues decreased $182 million due to:

o Mass revenues — decreased by $105 million, with a decrease of $57 million due to lower rates driven by lower revenue pricing on acquisitions and renewals consistent with competitive offers. In addition, a decrease of $23 million was due to 4% lower volumes which reflect 0.3% monthly net customer attrition since the end of the first quarter 2010 from increased competition. However, customer counts increased by 11,000 in the three months ended March 31, 2011. Favorable weather in both periods resulted in 11% higher customer usage when compared to ten-year normal weather.

o Commercial and Industrial revenue — decreased by $77 million due to 8% lower revenue rates driven by lower rates on variable customer contracts due to lower natural gas-related index prices in 2011 as compared to the same period in 2010 and lower rates on fixed price renewals. In addition, volumes were 8% lower driven by fewer customers in 2011.

· Retail cost of sales — decreased by $157 million for the three months ended March 31, 2011, as compared to 2010 due to:

o Supply costs and financial costs of energy — including intercompany purchases from the Texas region of $261 million and $225 million in 2011 and 2010, respectively, supply costs decreased by $143 million as compared to the same period in 2010. Excluding the estimated favorable impact of $27 million in 2010 for the termination of out-of-market supply contracts in conjunction with the 2009 CSRA unwind, supply costs decreased by $123 million attributed to 13% lower hedged prices and by $47 million from 6% lower volumes driven by fewer customers in 2011.

o Transmission and distribution charges — decreased by $14 million due to lower volumes transported and sold to customers in 2011.

Green Mountain Energy

· Retail operating revenues — for the three months ended March 31, 2011, retail operating revenues were $131 million from bundled retail electric sales in the Texas and New York markets and sales of renewable products and services to a public utility in Oregon, as well as utility programs in New York and New Jersey. Revenues were generated 65% and 35% from residential and commercial customers, respectively. Total metered customer counts were approximately 0.4 million and increased approximately 3%, or 12,000, in the quarter. Revenues exclude $10 million of contract amortization for customer contracts valued under purchase accounting.

· Retail cost of sales — for the three months ended March 31, 2011, retail costs of sales were $100 million and consisted of the following:

o Supply costs and financial costs of energy — supply costs, including the costs of power and renewable credits, totaled approximately $76 million for the quarter, including intercompany purchases of approximately $25 million. For fixed price term contracts, energy is procured at the time the sales contracts are executed, and for month to month customers, power is primarily purchased at market prices.

o Transmission and distribution charges — totaled $24 million for the quarter for the cost to transmit and deliver the power from the generation sources to the end use customers.

Table of Contents

Mark-to-market Activities

Mark-to-market activities include economic hedges that did not qualify for cash flow hedge accounting, ineffectiveness on cash flow hedges, and trading activities. Total net mark-to-market results increased by $185 million during the three months ended March 31, 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 March 31, 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	$	—		$	(59	)	$	8		$	6		$	—	$	—	$	—		$	38		$	(7	)
Reversal of previously recognized unrealized losses/(gains) on settled positions related to trading activity	—			12			(2		)	4			—		—		—			—			14
Net unrealized (losses)/gains on open positions related to economic hedges	(2		)	(47		)	(6		)	2			4		—		—			55			6
Net unrealized gains/(losses) on open positions related to trading activity	—			5			(5		)	(2		)	2		—		—			—			—
Total mark-to-market (losses)/gains in operating revenues	$	(2	)	$	(89	)	$	(5	)	$	10		$	6	$	—	$	—		$	93		$	13

Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	48		$	1		$	(2	)	$	(1	)	$	—	$	—	$	(3	)	$	(38	)	$	5
Reversal of loss positions acquired as part of the Reliant Energy acquisition as of May 1, 2009	28			—			—			—			—		—		—			—			28
Reversal of loss positions acquired as part of the Green Mountain Energy acquisition as of November 5, 2010	—			—			—			—			—		—		13			—			13
Net unrealized gains/(losses) on open positions related to economic hedges	110			10			3			5			—		—		15			(55		)	88
Total mark-to-market gains/(losses) in operating costs and expenses	$	186		$	11		$	1		$	4		$	—	$	—	$	25		$	(93	)	$	134

(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.

Table of Contents

	Three months ended March 31, 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 on settled positions related to economic hedges	$	—		$	(37	)	$	(24	)	$	—		$	—	$	(1	)	$	—	$	(11	)	$	(73	)
Reversal of previously recognized unrealized losses on settled positions related to trading activity	—			13			3			2			—		—			—		—			18
Net unrealized gains/(losses) on open positions related to economic hedges	—			222			30			(18		)	—		—			—		(124		)	110
Net unrealized gains on open positions related to trading activity	—			5			5			3			1		—			—		—			14
Total mark-to-market gains/(losses) in operating revenues	$	—		$	203		$	14		$	(13	)	$	1	$	(1	)	$	—	$	(135	)	$	69

Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(3	)	$	15		$	5		$	5		$	—	$	—		$	—	$	11		$	33
Reversal of loss positions acquired as part of the Reliant Energy acquisition as of May 1, 2009	90			—			—			—			—		—			—		—			90
Net unrealized (losses)/gains on open positions related to economic hedges	(375		)	9			6			6			—		—			—		124			(230		)
Total mark-to-market (losses)/gains in operating costs and expenses	$	(288	)	$	24		$	11		$	11		$	—	$	—		$	—	$	135		$	(107	)

(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 March 31, 2011, the gains on open positions were due to an increase in forward power and gas prices. Reliant Energy’s $28 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 $13 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 March 31, 2010, changes in the value of open positions were due to a decrease in forward power and gas prices. Reliant Energy’s $90 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 operations during the same period.

Table of Contents

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 March 31, 2011, and 2010. The unrealized financial and physical trading results are included in the mark-to-market activities above, while the realized financial and physical trading results are included in energy revenue. The Company’s trading activities are subject to limits within the Company’s Risk Management Policy.

	Three months ended March 31,
(In millions)	2011			2010
Trading gains/(losses)
Realized	$	(3	)	$	(11	)
Unrealized	14			32
Total trading gains	$	11		$	21

Other Revenues

(In millions)	Reliant Energy			Texas		Northeast		South Central		West		Thermal		Other			Total
Three months ended March 31, 2011	$	(42	)	$	17	$	6	$	6	$	1	$	40	$	(9	)	$	19
Three months ended March 31, 2010	$	(69	)	$	23	$	7	$	5	$	—	$	36	$	(8	)	$	(6	)

Other revenues in creased by $25 million for the three months ended March 31, 2011, as compared to the same period in 2010. This increase was driven by $15 million in lower contract amortization due to a $27 million reduction for Reliant Energy offset primarily by an increase for Green Mountain Energy of $10 million. Contract amortization for Reliant Energy and Green Mountain Energy is a reduction to revenue and represents the roll-off of in-market customer contracts valued under purchase accounting. In addition, Thermal revenue increased by $4 million due to the acquisition in 2010 of NRG Energy Center Phoenix.

Other Operating Costs

(In millions)	Reliant Energy		Texas		Northeast		South Central		West		Thermal		Other		Total
Three months ended March 31, 2011	$	38	$	128	$	59	$	19	$	18	$	28	$	8	$	298
Three months ended March 31, 2010	$	35	$	140	$	79	$	15	$	17	$	27	$	8	$	321

Other operating costs decreased by $23 million for the three months ended March 31, 2011, compared to the same period in 2010, due to:

· Operations and maintenance expense — decreased by $36 million due to the following:

o Northeast — decreased by $24 million as the 2010 period included a $14 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. The remaining decrease was primarily due to a decrease in operational labor from headcount reductions and a decrease in normal and major maintenance.

o Texas — decreased by $14 million as a result of less maintenance work during planned outages at the region’s baseload plants as compared to the same period in 2010.

These decreases in operations and maintenance expense were offset by:

· Asset retirement obligation expense — increased by $4 million, which primarily reflects a reduced estimate in the prior year period for an asset retirement obligation liability at the Huntley and Dunkirk plants.

· Contract amortization — decreased, primarily at Reliant Energy, resulting in an increase of $8 million in other operating costs, reflecting the roll-off of energy supply contracts valued in purchase accounting.

Table of Contents

Selling, General and Administrative Expenses

Selling, general and administrative expenses increased by $13 million for the three months ended March 31, 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 $18 million for the three months ended March 31, 2011. This increase was offset by a decrease in bad debt expense of $5 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 (Losses)/Earnings of Unconsolidated Affiliates

NRG’s equity (losses)/earnings from unconsolidated affiliates decreased by $16 million for the three months ended March 31, 2011, compared to the same period in 2010. The decrease is due to the changes in fair value of Sherbino’s forward gas contract, offset by equity earnings of $2 million from GenConn.

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, and consequently, NRG recorded an impairment charge of $481 million as of March 31, 2011.

Loss on Debt Extinguishment

A loss on the extinguishment of the 2014 Senior Notes of $28 million was recorded in 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.

Interest Expense

NRG’s interest expense increased by $20 million for the three months ended March 31, 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	$	23
Increase for 2018 Senior Notes issued in January 2011	17
Increase for project financings	5
Increase for tax-exempt bonds	4
Decrease for capitalized interest	(18		)
Decrease for 2014 Senior Notes redeemed in January and February 2011	(10		)
Other	(1		)
Total	$	20

Income Tax (Benefit)/Expense

For the three months ended March 31, 2011, NRG recorded an income tax benefit of $105 million as a result of a pre-tax loss of $365 million. For the same period in 2010, NRG recorded income tax expense of $65 million on pre-tax income of $123 million. The effective tax rate was 28.8% and 52.7% for the three months ended March 31, 2011, and 2010, respectively.

For the three months ended March 31, 2011, NRG’s overall effective tax rate was different than the statutory rate of 35% primarily due to the change in the valuation allowance resulting from capital losses generated in the quarter for which there were no projected capital gains or available tax planning strategies. For the three months ended March 31, 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.

Table of Contents

Liquidity and Capital Resources

Liquidity Position

As of March 31, 2011, and December 31, 2010, NRG’s liquidity, excluding collateral received, was approximately $4.0 billion and $4.3 billion, respectively, and comprised of the following:

(In millions)	March 31, 2011			December 31, 2010
Cash and cash equivalents	$	2,711		$	2,951
Funds deposited by counterparties	317			408
Restricted cash	13			8
Total cash	3,041			3,367
Funded Letter of Credit Facility availability	436			440
Revolving Credit Facility availability	853			853
Total liquidity	4,330			4,660
Less: Funds deposited as collateral by hedge counterparties	(317		)	(408		)
Total liquidity, excluding collateral received	$	4,013		$	4,252

For the three months ended March 31, 2011, total liquidity, excluding collateral received, decreased by $239 million due to lower cash and cash equivalent balances of $240 million. 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 March 31, 2011, were predominantly held in money market funds invested in treasury securities, treasury repurchase agreements or government agency debt.

The line item “Funds deposited by counterparties” represents the amounts that are held by NRG as a result of collateral posting obligations from 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 three months ended March 31, 2011.

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.

Table of Contents

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 March 31, 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 March 31, 2011:

Equivalent Net Sales Secured by First Lien Structure (a)	2011		2012		2013		2014
In MW (b)	2,235		1,050		128		7
As a percentage of total net baseload capacity (c)	33	%	16	%	2	%	—

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

(b) 2011 MW value consists of May through December positions only.

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 Repowering NRG; and (iv) corporate financial transactions including return of capital to shareholders.

Commercial Operations

NRG’s commercial operations activities require a significant amount of liquidity and capital resources. These liquidity requirements are primarily driven by: (i) margin and collateral posted with counterparties; (ii) initial collateral required to establish trading relationships; (iii) timing of disbursements and receipts (i.e., buying fuel before receiving energy revenues); and (iv) initial collateral for large structured transactions. As of March 31, 2011, commercial operations had total cash collateral outstanding of $147 million, and $693 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 March 31, 2011, total collateral held from counterparties was $317 million in cash and $11 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.

Table of Contents

Capital Expenditures

The following table and descriptions summarize the Company’s capital expenditures, including accruals, for maintenance, environmental and Repowering NRG, other than nuclear development, for the three months ended March 31, 2011, and the estimated capital expenditures and repowering investments forecast for the remainder of 2011.

(In millions)	Maintenance		Environmental		Repowering		Total
Northeast	$	1	$	39	$	—	$	40
Texas	33		—		1		34
South Central	1		—		—		1
West	1		—		76		77
Reliant Energy	2		—		—		2
Other	4		—		3		7
Total for the three months ended March 31, 2011	$	42	$	39	$	80	$	161
Estimated capital expenditures for the remainder of 2011	$	163	$	146	$	1,994	$	2,303

· Repowering NRG capital expenditures — For the three months ended March 31, 2011, the Company’s Repowering NRG capital expenditures included $66 million for the Company’s El Segundo project, $10 million for solar projects, and $3 million for the Company’s Princeton Hospital 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 $156 million and future capital expenditures are estimated to be approximately $1.7 billion, will be funded from a number of sources including third party partners, loan guarantees from the U.S. DOE and NRG contributions.

· Maintenance capital expenditures — For the three months ended March 31, 2011, the Company’s maintenance capital expenditures included $21 million in nuclear fuel expenditures related to STP Units 1 & 2. In addition, $35 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, SO 2 , 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 CAIR, 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.

Table of Contents

2011 Capital Allocation Program

On February 22, 2011, the Company announced its 2011 Capital Allocation Plan to purchase $180 million in common stock. As part of the 2011 plan, the Company entered into an ASR Agreement with a financial institution to repurchase $130 million of NRG common stock, and on February 25, 2011, 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. The Company’s share repurchases are 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 $390 million in maintenance and environmental capital expenditures in existing assets, and approximately $2.3 billion in solar and other projects under Repowering NRG, of which $81 million and $85 million have been spent by March 31, 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 $7.0 billion of existing credit facilities and senior notes to simplify its capital structure, better align covenant packages and extend debt maturities. As such, NRG is planning to restructure its $3.9 billion multi-tranche first lien facilities with a single $2.3 billion revolver and $1.6 billion term loan facility. The Company also expects to refinance its 2016 and 2017 senior note maturities as market conditions permit. 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 refinancing transactions will depend on market conditions and are therefore subject to change.

Table of Contents

Cash Flow Discussion

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

(In millions) Three months ended March 31,	2011			2010			Change
Net cash provided by operating activities	$	216		$	114		$	102
Net cash used by investing activities	(228		)	(194		)	(34		)
Net cash used by financing activities	(232		)	(408		)	176

Net Cash Provided By Operating Activities

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

The Company’s cash flow from operations was higher by $102 million in 2011 compared to 2010, due to a net reduction in cash paid for collateral of $348 million, offset by a net reduction of option premiums received of $166 million and an $83 million decrease in operating (loss)/income adjusted for non-cash charges.

Net Cash Used By Investing Activities

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

· Capital expenditures — NRG’s capital expenditures increased by $34 million due to increased spending on maintenance and Repowering NRG.

· Trading of emission allowances — Purchases of emission allowances decreased by $27 million for 2011 as compared to 2010.

· Proceeds from sale of assets — Proceeds from the sale of assets decreased $17 million primarily due to the receipt of $13 million in February 2011 on the sale of land as compared to the sale of Padoma in January 2010 for $29 million.

Net Cash Used By Financing Activities

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

· Share repurchases — During 2011, the Company paid $130 million to a financial institution to repurchase $130 million of NRG common stock under an ASR Agreement.

· Net (payments to)/ receipt from acquired derivatives that include financing elements — In 2011, the Company paid a total of $17 million for the settlement of gas swaps for Reliant Energy compared with a 2010 net receipt of $13 million for the settlement of gas swaps related to the Reliant Energy and Texas Genco acquisitions.

· Increase in issuance of debt — During 2011, the Company issued $1.2 billion under the 2018 Senior Notes and $86 million under existing debt facilities. During 2010, the Company issued $10 million under existing debt facilities.

· Debt payments — In 2011, the Company redeemed its 2014 Senior Notes for $1.2 billion and paid down $155 million of its Term Loan Facility, including the payment of excess cash flow, as discussed in Note 9, Long Term Debt to this Form 10-Q. In 2010, the Company paid down $237 million of its Term Loan Facility, including the payment of excess cash flow, and paid $190 million in principal to early settle the CSF I Debt.

Table of Contents

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

As of March 31, 2011, the Company had generated a domestic pre-tax book loss of $375 million and foreign pre-tax book income of $10 million. The Company has cumulative foreign NOL carryforwards of $280 million, of which $84 million will expire starting 2011 through 2018 and of which $195 million do not have an expiration date.

In addition to these amounts, the Company has $623 million of tax effected uncertain tax benefits which relate primarily to net operating losses for tax return purposes which have been classified as capital loss carryforwards for financial statement purposes. 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 $45 million in 2011.

However, as the position remains uncertain for the $623 million of tax effected uncertain tax benefits, the Company has recorded a non-current tax liability of $583 million and may accrue the remaining balance as an increase to non-current liabilities until final resolution with the related taxing authority. The $583 million non-current tax liability for uncertain tax benefits is primarily due to taxable earnings for which there are no NOLs available to offset for financial statement purposes and interest.

Table of Contents

New and On-going Company Initiatives and Development Projects

Repowering NRG 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. Construction of the 550 MW fast start, gas turbine combined cycle generating facility is expected to commence 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. The Middletown project, which is fully permitted, is in the advanced stages of construction, with a target commercial operation date of 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.

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 solar projects 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
Projects Under Agreement
Ivanpah	Ivanpah, CA	20 – 25 year	392	2013	Under Construction
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.

Table of Contents

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 by the end of second quarter 2011.

Roadrunner — This project, which is expected to be substantially complete by year end 2011, is expected to secure construction financing in the second quarter of 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 the Ivanpah Project. The Company will partner with BSE and Google to construct, finance and operate the largest solar thermal technology project in the world. The Ivanpah Project, 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 2013, with the second and third phases expected to follow within one year. In April 2011, the Bureau of Land Management, or BLM, advised that it will require the issuance of a revised biological opinion by the U.S. Fish & Wildlife Service, or FWS, prior to providing permission to proceed with the construction of Ivanpah’s second and third phases. Any delay by the BLM and/or FWS in delivering required approvals or opinions could have an adverse effect on the schedule for Ivanpah’s second and third phases of construction and operations.

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 second quarter 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.

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 second 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 Green Valley Solar Project, a 25 MW PV solar project with power sold to Tucson Electric Power under a 20-year PPA.

Offshore Wind

On March 24, 2011, the Bureau of Ocean Energy Management, Regulation and Enforcement announced that the U.S. Department of Interior was initiating the process to offer the first commercial wind lease under its “Smart from the Start” Atlantic Offshore Wind program, off the coast of Delaware. The decision follows a determination that there was no competitive interest for commercial wind energy development in this area of the Outer Continental Shelf, precluding the need for competitive bidding and thus allowing the Department to move toward a non-competitive lease agreement with NRG Bluewater for potential offshore wind development.

Table of Contents

Retail Growth Initiatives

Reliant Energy is continuing to use technology innovation through its eSense product offering as one of its points of differentiation. eSense is a comprehensive suite of technology solutions that leverage the advanced meter system network (smart meters) that is being rolled out to all customers in the competitive markets of ERCOT. Through the first quarter of 2011, Reliant has over 220,000 customers using at least one of eight different eSense products. Reliant’s eSense development is aided by the U.S. DOE grant received during 2010.

Reliant has substantially completed the launch of its C&I business in the Northeast. Expansion into the Northeast presents NRG and Reliant with the opportunity to extend their leading market position in Texas on a national level and leverage both the collateral and market transaction cost efficiency of owning generation assets in the Northeast. Reliant has also begun the application process to launch as a residential retail provider in the Northeast with the intent to fully leverage the integrated NRG-Reliant model they have successfully executed in Texas.

In addition, Reliant is now selling home services products through its primary sales and customer operations call centers. Reliant handles over 5 million calls per year and is taking the opportunity to extend its product offerings to include protection products such as surge protection, in home power line protection, HVAC maintenance and energy efficiency products like air filters. Reliant expects these products to not only add incremental earnings, but also reduce attrition as it continues to raise customer switching costs. 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. This represents a growth opportunity and strengthens our relationship with these customers.

Electric Vehicle Development

On November 18, 2010, NRG launched its eVgo sm Electric Vehicle, or EV, ecosystem in Houston, the start of a rollout across Texas in 2011. NRG plans to invest approximately $10 million in Houston’s EV ecosystem, and will be the first company to equip an entire major market with the privately funded infrastructure needed for successful EV adoption and integration.

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. eVgo Freedom Stations will be open 24/7 and, in addition to DC fast charging options enabling EV drivers to add 30 miles of range in as little as 10 minutes, the stations also have level 2 charging which can top off an EV with up to 25 miles of range for every hour. 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, with half in place by the end of this summer. NRG also plans to electrify the Interstate 45 corridor connecting these two cities in 2012.

Carbon Capture Sequestration Project

On March 9, 2010, NRG was selected by the U.S. Department of Energy, or U.S. DOE, to negotiate to receive up to $167 million, including funding from the American Recovery and Reinvestment Act, to build a post-combustion carbon capture demonstration unit at NRG’s WA Parish plant southwest of Houston with use of the captured carbon enhanced oil recovery in adjacent oil fields. NRG is currently progressing through the front-end engineering and design phase of the project, and 50% of the costs of this phase are being reimbursed by the U.S. DOE. Construction is projected to begin in late 2012 with commercial operations anticipated in the fourth quarter of 2014.

Table of Contents

Off-Balance Sheet Arrangements

Obligations under Certain Guarantee Contracts

NRG and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include financial and performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications.

Retained or Contingent Interests

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

Derivative Instrument Obligations

The Company’s 3.625% Preferred Stock includes a feature which is considered an embedded derivative per ASC 815. Although it is considered an embedded derivative, it is exempt from derivative accounting as it is excluded from the scope pursuant to ASC 815. As of March 31, 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 March 31, 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 $236 million as of March 31, 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 Annual Report on Form 10-K for the year ended December 31, 2010. 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 three months ended March 31, 2011.

Table of Contents

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 March 31, 2011, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at March 31, 2011. The increase in NRG’s net derivative asset at March 31, 2011, as compared to December 31, 2010, was driven by the increases 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	(77		)
Changes in fair value	107
Fair value of contracts as of March 31, 2011	$	702

	Fair Value of Contracts as of March 31, 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	$	39		$	(5	)	$	1		$	—		$	35
Level 2	342			368			(3		)	(29		)	678
Level 3	(19		)	7			1			—			(11		)
Total	$	362		$	370		$	(1	)	$	(29	)	$	702

The Company applies a credit reserve to reflect credit risk, which is calculated based on published default probabilities. As of March 31, 2011, the credit reserve resulted in a $1 million decrease in fair value which is composed of a $1 million gain in OCI and a $2 million loss in derivative revenue and cost of operations.

Based on a sensitivity analysis, the impact of a $1 per MMBtu increase or decrease in natural gas prices across the term of the derivative contracts would cause a change of approximately $95 million in the net value of derivatives as of March 31, 2011.

Table of Contents

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 recorded an impairment charge of $481 million as of March 31, 2011.

Table of Contents

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, 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 March 31, 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 $52 million.

The following table summarizes average, maximum and minimum VaR for NRG for the three months ended March 31, 2011, and 2010:

(In millions)	2011		2010
VaR as of March 31	$	52	$	51
Three months ended March 31:
Average	$	51	$	47
Maximum	56		55
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 March 31, 2011, for the entire term of these instruments entered into for both asset management and trading, was approximately $15 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 March 31, 2011, the Company had various interest rate swap agreements with notional amounts totaling approximately $1.2 billion. If the swaps had been discontinued on March 31, 2011, the Company would have owed the counterparties approximately $70 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 March 31, 2011, a 1% change in interest rates would result in a $7 million change in interest expense on a rolling twelve month basis.

As of March 31, 2011, the fair value of the Company’s long-term debt and funded letter of credit was $10.4 billion and the related carrying amount was $10.1 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 $656 million.

Table of Contents

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 $148 million as of March 31, 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 $16 million as of March 31, 2011. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of March 31, 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 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.

Table of Contents

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 first 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.

Table of Contents

PART II — OTHER INFORMATION

ITEM 1 — LEGAL PROCEEDINGS

For a discussion of material legal proceedings in which NRG was involved through March 31, 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

None.

ITEM 3 — DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4 — (REMOVED AND RESERVED)

ITEM 5 — OTHER INFORMATION

None.

Table of Contents

ITEM 6 — EXHIBITS

Exhibits

1.1		Purchase Agreement, dated January 11, 2011, among NRG Energy, Inc., the guarantors named therein and J.P. Morgan Securities LLC, as initial purchaser. (1)

4.1		Forty-Second Supplemental Indenture, dated January 26, 2011, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York. (1)

4.2		Form of 7.625% Senior Note due 2018 (incorporated by reference to Exhibit 4.1). (1)

4.3		Registration Rights Agreement, dated January 26, 2011, among NRG Energy, Inc., the guarantors named therein and J.P. Morgan Securities, LLC, as initial purchaser. (1)

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

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

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

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

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema

101.CAL		XBRL Taxonomy Extension Calculation Linkbase

101.DEF		XBRL Taxonomy Extension Definition Linkbase

101.LAB		XBRL Taxonomy Extension Label Linkbase

101.PRE		XBRL Taxonomy Extension Presentation Linkbase

(1) Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on January 28, 2011.

Table of Contents

SIGNATURES

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

	NRG ENERGY, INC.
	(Registrant)

	By:

		/s/ DAVID W. CRANE
		David W. Crane
		Chief Executive Officer
		(Principal Executive Officer)

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

		/s/ JAMES J. INGOLDSBY
		James J. Ingoldsby
Date: May 5, 2011		Chief Accounting Officer
		(Principal Accounting Officer)

Table of Contents

EXHIBIT INDEX

Exhibits

1.1		Purchase Agreement, dated January 11, 2011, among NRG Energy, Inc., the guarantors named therein and J.P. Morgan Securities LLC, as initial purchaser. (1)

4.1		Forty-Second Supplemental Indenture, dated January 26, 2011, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York. (1)

4.2		Form of 7.625% Senior Note due 2018 (incorporated by reference to Exhibit 4.1). (1)

4.3		Registration Rights Agreement, dated January 26, 2011, among NRG Energy, Inc., the guarantors named therein and J.P. Morgan Securities, LLC, as initial purchaser. (1)

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

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

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

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

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema

101.CAL		XBRL Taxonomy Extension Calculation Linkbase

101.DEF		XBRL Taxonomy Extension Definition Linkbase

101.LAB		XBRL Taxonomy Extension Label Linkbase

101.PRE		XBRL Taxonomy Extension Presentation Linkbase

(1) Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on January 28, 2011.

TABLE OF CONTENTS

Part I Financial Information Item 1 Condensed Consolidated Financial Statements and Notes Note 1 Basis Of Presentation Note 2 Other Cash Flow Information Note 3 Comprehensive (loss)/income Note 4 Business Acquisitions and Disposition Note 5 Nuclear Innovation North America Llc Developments, Including Impairment Charge Note 6 Fair Value Of Financial Instruments Note 7 Nuclear Decommissioning Trust Fund Note 8 Accounting For Derivative Instruments and Hedging Activities Note 9 Long-term Debt Note 10 Variable Interest Entities, Or Vies Note 11 Changes in Capital Structure Note 12 (loss)/earnings Per Share Note 13 Segment Reporting Note 14 Income Taxes Note 15 Benefit Plans and Other Postretirement Benefits Note 16 Commitments and Contingencies Note 17 Regulatory Matters Note 18 Environmental Matters Note 19 Condensed Consolidating Financial Information Item 2 Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 3 Quantitative and Qualitative Disclosures About Market Risk Item 4 Controls and Procedures Part II Other Information Item 1 Legal Proceedings Item 1A Risk Factors Item 2 Unregistered Sales Of Equity Securities and Use Of Proceeds Item 3 Defaults Upon Senior Securities Item 4 (removed and Reserved)Item 5 Other Information Item 6 Exhibits

NRG 10-Q Quarter ended March 31, 2011