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, 2012
o	Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Commission File Number: 001-15891

NRG Energy, Inc.

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)	41-1724239 (I.R.S. Employer Identification No.)
211 Carnegie Center, Princeton, New Jersey (Address of principal executive offices)	08540 (Zip Code)

(609) 524-4500

(Registrant’s telephone number, including area code)

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

YesxNoo

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).

YesxNoo

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

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

YesoNox

As of April 30, 2012, there were 227,719,443 shares of common stock outstanding, par value $0.01 per share.

TABLE OF CONTENTS

Index

CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION	3
GLOSSARY OF TERMS	4
PART I — FINANCIAL INFORMATION	7
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES	7
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	44
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	68
ITEM 4 — CONTROLS AND PROCEDURES	70
PART II — OTHER INFORMATION	71
ITEM 1 — LEGAL PROCEEDINGS	71
ITEM 1A — RISK FACTORS	71
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	71
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES	71
ITEM 4 — MINE SAFETY DISCLOSURES	71
ITEM 5 — OTHER INFORMATION	71
ITEM 6 — EXHIBITS	72
SIGNATURES	73

2

CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION

This Quarterly Report on Form 10-Q includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or 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 Item 1A — Risk Factors Related to NRG Energy, Inc., in Part I, Item 1A of the Company's Annual Report on Form 10-K for the year ended December 31, 2011, 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 strategy of developing and building new power generation facilities, including new solar projects;

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

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

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

• NRG's ability to maintain retail market share;

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

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

3

GLOSSARY OF TERMS

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:

2011 Form 10-K	NRG’s Annual Report on Form 10-K for the year ended December 31, 2011
2011 Revolving Credit Facility	The Company's $2.3 billion revolving credit facility due 2016, a component of the 2011 Senior Credit Facility
2011 Senior Credit Facility	As of July 1, 2011, NRG's senior secured facility, comprised of a $1.6 billion term loan facility and a $2.3 billion revolving credit facility
2011 Term Loan Facility	The Company's $1.6 billion term loan facility due 2018, a component of the 2011 Senior Credit Facility
316(b) Rule	A section of the Clean Water Act regulating cooling water intake structures
Baseload capacity	Coal and nuclear electric power generation capacity normally expected to serve loads on an around-the-clock basis throughout the calendar year
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CAISO	California Independent System Operator
Capital Allocation Plan	Share repurchase and shareholder dividend program
Capital Allocation Program	NRG's plan of allocating capitalbetween debt reduction, reinvestmentin the business, sharerepurchases and shareholder dividends through the CapitalAllocation Plan
CDWR	California Department of Water Resources
C&I	Commercial, industrial and governmental/institutional
CFTC	U.S. Commodity Futures Trading Commission
CO2	Carbon dioxide
CSAPR	Cross-State Air Pollution Rule
Distributed Solar	Solar power projects, typically less than 20 MW in size (on an alternating current, or AC, basis), that primarily sell power produced to customers for usage on site, or are interconnected to sell power into the local distribution grid
DNREC	Delaware Department of Natural Resources and Environmental Control
Energy Plus	Energy Plus Holdings LLC
ERCOT	Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas
Exchange Act	The Securities Exchange Act of 1934, as amended
FERC	Federal Energy Regulatory Commission
FFB	Federal Financing Bank
GHG	Greenhouse Gases
Green Mountain Energy	Green Mountain Energy Company

4

GWh	Gigawatt hour
Heat Rate	A measure of thermal efficiency computed by dividing the total BTU content of the fuel burned by the resulting kWhs generated. Heat rates can be expressed as either gross or net heat rates, depending whether the electricity output measured is gross or net generation and is generally expressed as BTU per net kWh
ISO	Independent System Operator, also referred to as Regional Transmission Organizations, or RTO
ISO-NE	ISO New England Inc.
LIBOR	London Inter-Bank Offered Rate
LTIP	Long-Term Incentive Plan
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
NERC	North American Electric Reliability Corporation
NINA	Nuclear Innovation North America LLC
NOx	Nitrogen oxide
NPNS	Normal Purchase Normal Sale
NRC	U.S. Nuclear Regulatory Commission
NYPSC	New York Public Service Commission
OCI	Other comprehensive income
PJM	PJM Interconnection, LLC
PJM market	The wholesale and retail electric market operated by PJM primarily in all or parts of Delaware, the District of Columbia, Illinois, Maryland, New Jersey, Ohio, Pennsylvania, Virginia and West Virginia
PM 2.5	Particulate matter particles with a diameter of 2.5 micrometers or less
PPA	Power Purchase Agreement
PUCT	Public Utility Commission of Texas
Repowering	Technologies utilized to replace, rebuild, or redevelop major portions of an existing electrical generating facility, not only to achieve a substantial emissions reduction, but also to increase facility capacity, and improve system efficiency
SEC	United States Securities and Exchange Commission
Securities Act	The Securities Act of 1933, as amended
Senior Notes	The Company’s $6.1 billion outstanding unsecured senior notes, consisting of $1.1 billion of 7.375% senior notes due 2017, $1.2 billion of 7.625% senior notes due 2018, $700 million of 8.5% senior notes due 2019, $800 million of 7.625% senior notes due 2019, $1.1 billion of 8.25% senior notes due 2020 and $1.2 billion of 7.875% senior notes due 2021

5

SO2	Sulfur dioxide
STP	South Texas Project — nuclear generating facility located near Bay City, Texas in which NRG owns a 44% interest
Term Loan Facility	Prior to July 1, 2011, a senior first priority secured term loan, of which approximately $608 million would have matured on February 1, 2013, and $990 million would have matured on August 31, 2015, and was a component of NRG’s Senior Credit Facility. On July 1, 2011, NRG replaced its Senior Credit Facility, including the Term Loan Facility, with the 2011 Senior Credit Facility.
U.S.	United States of America
U.S. DOE	United States Department of Energy
U.S. EPA	United States Environmental Protection Agency
U.S. GAAP	Accounting principles generally accepted in the United States
Utility Scale Solar	Solar power projects, typically 20 MW or greater in size (on an alternating current, or AC, basis), that are interconnected into the transmission or distribution grid to sell power at a wholesale level
VaR	Value at Risk
VIE	Variable Interest Entity

6

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)	2012			2011
Operating Revenues
Total operating revenues	$	1,862		$	1,995
Operating Costs and Expenses
Cost of operations	1,573			1,324
Depreciation and amortization	230			205
Selling, general and administrative	221			143
Development costs	8			9
Total operating costs and expenses	2,032			1,681
Operating (Loss)/Income	(170		)	314
Other Income/(Expense)
Equity in earnings/(losses) of unconsolidated affiliates	8			(2		)
Impairment charge on investment	(1		)	(481		)
Other income, net	2			5
Loss on debt extinguishment	—			(28		)
Interest expense	(165		)	(173		)
Total other expense	(156		)	(679		)
Loss Before Income Taxes	(326		)	(365		)
Income tax benefit	(120		)	(105		)
Net Loss	(206		)	(260		)
Less: Net income attributable to noncontrolling interest	1			—
Net Loss Attributable to NRG Energy, Inc.	(207		)	(260		)
Dividends for preferred shares	2			2
Loss Available for Common Stockholders	$	(209	)	$	(262	)
Loss Per Share Attributable to NRG Energy, Inc. Common Stockholders
Weighted average number of common shares outstanding — basic and diluted	228			247
Net loss per weighted average common share — basic and diluted	$	(0.92	)	$	(1.06	)

See accompanying notes to condensed consolidated financial statements.

7

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(Unaudited)

	Three months ended March 31,
	2012			2011
	(In millions)
Net Loss	$	(206	)	$	(260	)
Other comprehensive income/(loss), net of tax
Unrealized loss on derivatives, net of income tax benefit of $5 and $48	(9		)	(82		)
Foreign currency translation adjustments, net of income tax expense of $3 and $6	6			12
Defined benefit plans	—			1
Other comprehensive loss	(3		)	(69		)
Comprehensive loss	(209		)	(329		)
Less: Comprehensive income attributable to noncontrolling interest	1			—
Comprehensive loss attributable to NRG Energy, Inc.	(210		)	(329		)
Dividends for preferred shares	2			2
Comprehensive loss available for common stockholders	$	(212	)	$	(331	)

See accompanying notes to condensed consolidated financial statements.

8

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

	March 31, 2012			December 31, 2011
(In millions, except shares)	(unaudited)
ASSETS
Current Assets
Cash and cash equivalents	$	1,014		$	1,105
Funds deposited by counterparties	199			258
Restricted cash	217			292
Accounts receivable — trade, less allowance for doubtful accounts of $19 and $23	716			834
Inventory	392			308
Derivative instruments	5,150			4,216
Cash collateral paid in support of energy risk management activities	498			311
Prepayments and other current assets	272			273
Total current assets	8,458			7,597
Property, plant and equipment, net of accumulated depreciation of $4,768 and $4,570	14,376			13,621
Other Assets
Equity investments in affiliates	643			640
Note receivable — affiliate and capital leases, less current portion	370			342
Goodwill	1,886			1,886
Intangible assets, net of accumulated amortization of $1,476 and $1,452	1,340			1,419
Nuclear decommissioning trust fund	456			424
Derivative instruments	649			450
Other non-current assets	352			336
Total other assets	5,696			5,497
Total Assets	$	28,530		$	26,715
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	71		$	87
Accounts payable	1,080			808
Derivative instruments	4,824			3,751
Deferred income taxes	92			127
Cash collateral received in support of energy risk management activities	199			258
Accrued expenses and other current liabilities	619			640
Total current liabilities	6,885			5,671
Other Liabilities
Long-term debt and capital leases	10,150			9,745
Nuclear decommissioning reserve	340			335
Nuclear decommissioning trust liability	279			254
Deferred income taxes	1,300			1,389
Derivative instruments	708			464
Out-of-market commodity contracts	176			183
Other non-current liabilities	810			756
Total non-current liabilities	13,763			13,126
Total Liabilities	20,648			18,797
3.625% convertible perpetual preferred stock (at liquidation value, net of issuance costs)	249			249
Commitments and Contingencies
Stockholders’ Equity
Common stock	3			3
Additional paid-in capital	5,374			5,346
Retained earnings	3,777			3,987
Less treasury stock, at cost — 76,587,776 and 76,664,199 shares, respectively	(1,922		)	(1,924		)
Accumulated other comprehensive income	71			74
Noncontrolling interest	330			183
Total Stockholders’ Equity	7,633			7,669
Total Liabilities and Stockholders’ Equity	$	28,530		$	26,715

See accompanying notes to condensed consolidated financial statements.

9

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three months ended March 31,
	2012			2011
	(In millions)
Cash Flows from Operating Activities
Net loss	$	(206	)	$	(260	)
Adjustments to reconcile net loss to net cash (used)/provided by operating activities:
Distributions and equity in earnings of unconsolidated affiliates	—			9
Depreciation and amortization	230			205
Provision for bad debts	7			8
Amortization of nuclear fuel	6			11
Amortization of financing costs and debt discount/premiums	8			8
Amortization of intangibles and out-of-market commodity contracts	42			48
Changes in deferred income taxes and liability for uncertain tax benefits	(129		)	(109		)
Changes in nuclear decommissioning trust liability	8			10
Changes in derivative instruments	187			(130		)
Changes in collateral deposits supporting energy risk management activities	(187		)	176
Impairment charge on investment	—			481
Cash used by changes in other working capital	(42		)	(241		)
Net Cash (Used)/Provided by Operating Activities	(76		)	216
Cash Flows from Investing Activities
Capital expenditures	(639		)	(219		)
Increase in restricted cash, net	(20		)	(5		)
Decrease in restricted cash to support equity requirements for U.S. DOE funded projects	95			—
(Increase)/decrease in notes receivable	(7		)	12
Investments in nuclear decommissioning trust fund securities	(126		)	(105		)
Proceeds from sales of nuclear decommissioning trust fund securities	119			95
Proceeds from renewable energy grants	28			—
Other	7			(6		)
Net Cash Used by Investing Activities	(543		)	(228		)
Cash Flows from Financing Activities
Payment of dividends to preferred stockholders	(2		)	(2		)
Payment for treasury stock	—			(130		)
Net payments for settlement of acquired derivatives that include financing elements	(20		)	(17		)
Sale proceeds and other contributions from noncontrolling interests in subsidiaries	178			—
Proceeds from issuance of long-term debt	415			1,286
Payment of debt issuance and hedging costs	(10		)	(8		)
Payments for short and long-term debt	(34		)	(1,361		)
Net Cash Provided/(Used) by Financing Activities	527			(232		)
Effect of exchange rate changes on cash and cash equivalents	1			4
Net Decrease in Cash and Cash Equivalents	(91		)	(240		)
Cash and Cash Equivalents at Beginning of Period	1,105			2,951
Cash and Cash Equivalents at End of Period	$	1,014		$	2,711

See accompanying notes to condensed consolidated financial statements.

10

NRG ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 — Basis of Presentation

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

The accompanying unaudited interim condensed consolidated financial statements have been prepared in accordance with the Securities and Exchange Commission's, or SEC's, regulations for interim financial information and with the instructions to Form 10-Q. Accordingly, they do not include all of the information and notes required by generally accepted accounting principles for complete financial statements. The following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to the Company's financial statements in its Annual Report on Form 10-K for the year ended December 31, 2011, or 2011 Form 10-K. Interim results are not necessarily indicative of results for a full year.

In the opinion of management, the accompanying unaudited interim condensed consolidated financial statements contain all material adjustments consisting of normal and recurring accruals necessary to present fairly the Company's consolidated financial position as of March 31, 2012, and the results of operations, comprehensive loss and cash flows for the three months ended March 31, 2012, and 2011.

Use of Estimates

The preparation of consolidated financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions. These estimates and assumptions impact the reported amount of assets and liabilities and disclosures of contingent assets and liabilities as of the date of the consolidated financial statements. They also impact the reported amount of net earnings during the reporting period. Actual results could be different from these estimates.

Note 2 — Summary of Significant Accounting Policies

Other Cash Flow Information

NRG’s investing activities exclude capital expenditures of $327 million which were accrued and unpaid at March 31, 2012, primarily for solar projects under construction.

Tax Credits

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

11

Recent Accounting Developments

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

Note 3 — Business Acquisitions and Dispositions

2012 Disposition

Agua Caliente— On January 18, 2012, the Company completed the sale of a 49% interest in NRG Solar AC Holdings LLC, the indirect owner of the Agua Caliente project, to MidAmerican Energy Holdings Company, or MidAmerican. A majority of the $122 million of cash consideration received at closing represented 49% of construction costs funded by NRG's equity contributions. The excess of the consideration over the carrying value of the divested interest was recorded to additional paid-in capital. MidAmerican will fund its proportionate share of future equity contributions and other credit support for the project. NRG continues to hold a majority interest in and consolidate the project. MidAmerican's non-controlling interest on the Company's balance sheet as of March 31, 2012 represents its capital contributions.

2011 Acquisitions

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

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

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

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

12

Note 5 — Fair Value of Financial Instruments

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

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

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

	As of March 31, 2012				As of December 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Assets:
Notes receivable	$	182	$	187	$	156	$	161
Liabilities:
Long-term debt, including current portion	10,118		10,073		9,729		9,716

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

Recurring Fair Value Measurements

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

13

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

	As of March 31, 2012
	Fair Value
	Level 1		Level 2		Level 3		Total
	(In millions)
Investment in available-for-sale securities (classified within other     non-current assets):
Debt securities	$	—	$	—	$	8	$	8
Marketable equity securities	1		—		—		1
Trust fund investments:
Cash and cash equivalents	2		—		—		2
U.S. government and federal agency obligations	36		—		—		36
Federal agency mortgage-backed securities	—		60		—		60
Commercial mortgage-backed securities	—		7		—		7
Corporate debt securities	—		65		—		65
Equity securities	236		—		46		282
Foreign government fixed income securities	—		5		—		5
Derivative assets:
Commodity contracts	3,365		2,258		176		5,799
Total assets	$	3,640	$	2,395	$	230	$	6,265
Derivative liabilities:
Commodity contracts	$	3,457	$	1,847	$	133	$	5,437
Interest rate contracts	—		95		—		95
Total liabilities	$	3,457	$	1,942	$	133	$	5,532

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

14

There were no transfers during the three months ended March 31, 2012, and 2011, between Levels 1 and 2. The following tables reconcile, for the three months ended March 31, 2012, and 2011, the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements at least annually using significant unobservable inputs:

	Three months ended March 31, 2012
	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Debt Securities		Trust Fund Investments
					Derivatives(a)			Total
	(In millions)
Beginning balance as of January 1, 2012	$	7	$	42	$	8		$	57
Total gains - realized/unrealized:
Included in earnings	—		—		17			17
Included in OCI	1		—		—			1
Included in nuclear decommissioning obligations	—		4		—			4
Purchases	—		—		(4		)	(4		)
Transfers into Level 3 (b)	—		—		10			10
Transfers out of Level 3 (b)	—		—		12			12
Ending balance as of March 31, 2012	$	8	$	46	$	43		$	97
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, 2012	$	—	$	—	$	18		$	18

	Three months ended March 31, 2011
	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Debt Securities		Trust Fund Investments
					Derivatives(a)			Total
	(In millions)
Beginning balance as of January 1, 2011	$	8	$	39	$	(27	)	$	20
Total gains/(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

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

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

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

15

Derivative fair value measurements

The majority of NRG's contracts are exchange-traded contracts with readily available quoted market prices. A portion of NRG's contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter and on-line exchanges. For the majority of NRG markets, the Company receives quotes from multiple sources. To the extent that NRG receives multiple quotes, the Company's prices reflect the average of the bid-ask mid-point prices obtained from all sources that NRG believes provide the most liquid market for the commodity. If the Company receives one quote, then the mid-point of the bid-ask spread for that quote is used. The terms for which such price information is available vary by commodity, region and product. A significant portion of the fair value of the Company's derivative portfolio is based on price quotes from brokers in active markets who regularly facilitate those transactions and the Company believes such price quotes are executable. The Company does not use third party sources that derive price based on proprietary models or market surveys. The remainder of the assets and liabilities represent contracts for which external sources or observable market quotes are not available for the whole term or for certain delivery months or the contracts are retail and load following power contracts. These contracts are valued using various valuation techniques including but not limited to internal models that apply fundamental analysis of the market and corroboration with similar markets. Contracts valued with prices provided by models and other valuation techniques make up 3% of the total derivative assets and 2% of the total derivative liabilities.

The fair value of each contract is discounted using a risk free interest rate. In addition, the Company applies a credit reserve to reflect credit risk which is calculated based on published default probabilities. To the extent that NRG's net exposure under a specific master agreement is an asset, the Company uses the counterparty's default swap rate. If the exposure under a specific master agreement is a liability, the Company uses NRG's default swap rate. The credit reserve is added to the discounted fair value to reflect the exit price that a market participant would be willing to receive to assume NRG's liabilities or that a market participant would be willing to pay for NRG's assets. As of March 31, 2012, the credit reserve resulted in an $8 million increase in fair value which is composed of a $1 million gain in Other Comprehensive Income, or OCI, and a $7 million gain in operating revenue and cost of operations. 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 2011 Form 10-K, the following item is a discussion of the concentration of credit risk for the Company's contractual obligations. Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. NRG is exposed to counterparty credit risk through various activities including wholesale sales, fuel purchases and retail supply arrangements, and retail customer credit risk through its retail load activities.

Counterparty Credit Risk

The Company monitors and manages counterparty credit risk through credit policies that include: (i) an established credit approval process; (ii) daily monitoring of counterparties' credit limits; (iii) the use of credit mitigation measures such as margin, collateral, prepayment arrangements, or volumetric limits; (iv) the use of payment netting arrangements; and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty. Risk surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. The Company seeks to mitigate counterparty credit risk with a diversified portfolio of counterparties. The Company also has credit protection within various agreements to call on additional collateral support if and when necessary. Cash margin is collected and held at NRG to cover the credit risk of the counterparty until positions settle.

As of March 31, 2012, counterparty credit exposure to a significant portion of the Company's counterparties was $1.1 billion and NRG held collateral (cash and letters of credit) against those positions of $204 million, resulting in a net exposure of $917 million. Counterparty credit exposure is discounted at the risk free rate. The following table highlights the counterparty credit quality and the net counterparty credit exposure by industry sector. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market and Normal Purchase Normal Sale, or NPNS, and non-derivative transactions. The exposure is shown net of collateral held, and includes amounts net of receivables or payables.

16

	Net Exposure (a)
Category	(% of Total)
Financial institutions	54	%
Utilities, energy merchants, marketers and other	43
Coal and emissions	1
Independent System Operators, or ISOs	2
Total as of March 31, 2012	100	%

	Net Exposure (a)
Category	(% of Total)
Investment grade	78	%
Non-Investment grade	1
Non-rated (b)	21
Total as of March 31, 2012	100	%

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

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

NRG has counterparty credit risk exposure to certain counterparties representing more than 10% of total net exposure discussed above and the aggregate of such counterparties was $269 million. Approximately 92% of NRG's positions relating to this credit risk roll-off by the end of 2013. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration. Given the credit quality, diversification and term of the exposure in the portfolio, NRG does not anticipate a material impact on the Company's financial position or results of operations from nonperformance by any of NRG's counterparties.

Counterparty credit exposure described above excludes credit risk exposure under certain long term agreements, including California tolling agreements, South Central load obligations, solar Power Purchase Agreements, or PPAs, 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, 2012, credit risk exposure to these counterparties allocable to NRG's ownership interests was approximately $939 million for the next five years. This amount excludes potential credit exposures for projects with long term PPAs that have not reached commercial operations. Many of these power contracts are with utilities or public power entities that have strong credit quality and specific public utility commission or other regulatory support. In the case of the coal supply agreement, NRG holds a lien against the underlying asset. These factors significantly reduce the risk of loss.

Retail Customer Credit Risk

NRG is exposed to retail credit risk through the Company's retail electricity providers, which serve Commercial, industrial and governmental/institutional, or C&I, customers and the Residential and small business, or Mass, market. Retail credit risk results when a customer fails to pay for services rendered. The losses may result from both nonpayment of customer accounts receivable and the loss of in-the-money forward value. NRG manages retail credit risk through the use of established credit policies that include monitoring of the portfolio, and the use of credit mitigation measures such as deposits or prepayment arrangements.

As of March 31, 2012, the Company's retail customer credit exposure was diversified across many customers and various industries, with a significant portion of the exposure with government entities.

17

Note 6 — Nuclear Decommissioning Trust Fund

NRG's nuclear decommissioning trust fund assets, which are for its portion of the decommissioning of the South Texas Project, or STP Units 1 & 2, are comprised of securities classified as available-for-sale and recorded at fair value based on actively quoted market prices. NRG accounts for the nuclear decommissioning trust fund in accordance with ASC 980, Regulated Operations, or ASC 980, because the Company's nuclear decommissioning activities are subject to approval by the Public Utility Commission of Texas, or PUCT, with regulated rates that are designed to recover all decommissioning costs and that can be charged to and collected from the ratepayers per PUCT mandate. Since the Company is in compliance with PUCT rules and regulations regarding decommissioning trusts and the cost of decommissioning is the responsibility of the Texas ratepayers, not NRG, all realized and unrealized gains or losses (including other-than-temporary impairments) related to the Nuclear Decommissioning Trust Fund are recorded to the Nuclear Decommissioning Trust Liability and are not included in net income or accumulated other comprehensive income, consistent with regulatory treatment.

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

	As of March 31, 2012							As of December 31, 2011
(In millions, except otherwise noted)	Fair Value		Unrealized Gains		Unrealized Losses		Weighted- average maturities (in years)	Fair Value		Unrealized Gains		Unrealized Losses		Weighted- average maturities (in years)
Cash and cash equivalents	$	2	$	—	$	—	—	$	2	$	—	$	—	—
U.S. government and federal agency obligations	35		2		—		11	43		3		—		10
Federal agency mortgage-backed securities	60		2		—		23	63		3		—		23
Commercial mortgage-backed securities	7		—		—		30	7		—		—		28
Corporate debt securities	65		3		1		10	54		3		1		10
Equity securities	282		141		—		—	251		113		1		—
Foreign government fixed income securities	5		—		—		7	4		—		—		8
Total	$	456	$	148	$	1		$	424	$	122	$	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,
	2012		2011
	(In millions)
Realized gains	$	3	$	2
Realized losses	2		2
Proceeds from sale of securities	119		95

18

Note 7 — Accounting for Derivative Instruments and Hedging Activities

This footnote should be read in conjunction with the complete description under Note 6, Accounting for Derivative Instruments and Hedging Activities, to the Company's 2011 Form 10-K.

Energy-Related Commodities

As of March 31, 2012, NRG had energy-related derivative financial instruments extending through 2015, which are designated as cash flow hedges.

Interest Rate Swaps

NRG is exposed to changes in interest rates through the Company's issuance of variable and fixed rate debt. In order to manage the Company's interest rate risk, NRG enters into interest rate swap agreements. As of March 31, 2012, NRG had interest rate derivative instruments on recourse debt extending through 2013 and on non-recourse debt extending through 2029, the majority of which are designated as cash flow hedges.

Volumetric Underlying Derivative Transactions

The following table summarizes the net notional volume buy/(sell) of NRG's open derivative transactions broken out by commodity, excluding those derivatives that qualified for the NPNS exception as of March 31, 2012, and December 31, 2011. Option contracts are reflected using delta volume. Delta volume equals the notional volume of an option adjusted for the probability that the option will be in-the-money at its expiration date.

		Total Volume
Commodity	Units	March 31, 2012			December 31, 2011
		(In millions)
Emissions	Short Ton	(2		)	(2		)
Coal	Short Ton	30			37
Natural Gas	MMBtu	(232		)	13
Oil	Barrel	1			1
Power	MWh	6			4
Interest	Dollars	$	2,175		$	2,121

19

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, 2012		December 31, 2011		March 31, 2012		December 31, 2011
Derivatives Designated as Cash Flow or Fair Value Hedges:
Interest rate contracts current	$	—	$	—	$	17	$	39
Interest rate contracts long-term	—		—		52		68
Commodity contracts current	269		318		2		—
Commodity contracts long-term	—		—		3		1
Total Derivatives Designated as Cash Flow or Fair Value Hedges	269		318		74		108
Derivatives Not Designated as Cash Flow or Fair Value Hedges:
Interest rate contracts current	—		—		22		—
Interest rate contracts long-term	—		—		4		1
Commodity contracts current	4,881		3,898		4,783		3,712
Commodity contracts long-term	649		450		649		394
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges	5,530		4,348		5,458		4,107
Total Derivatives	$	5,799	$	4,666	$	5,532	$	4,215

Accumulated Other Comprehensive Income

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

	Three months ended March 31, 2012									Three months ended March 31, 2011
(In millions)	Energy Commodities			Interest Rate			Total			Energy Commodities			Interest Rate			Total
Accumulated OCI beginning balance	$	188		$	(56	)	$	132		$	488		$	(47	)	$	441
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts	(31		)	3			(28		)	(98		)	11			(87		)
Mark-to-market of cash flow hedge accounting contracts	13			6			19			2			3			5
Accumulated OCI ending balance, net of $82 and $220 tax, respectively	$	170		$	(47	)	$	123		$	392		$	(33	)	$	359
Gains/(losses) expected to be realized from OCI during the next 12 months, net of $66 and $154 tax respectively	$	137		$	(23	)	$	114		$	265		$	(2	)	$	263
(Losses)/gains recognized in income from the ineffective portion of cash flow hedges	$	(1	)	$	(2	)	$	(3	)	$	3		$	(1	)	$	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.

20

Impact of Derivative Instruments on the Statement of Operations

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

The following table summarizes the pre-tax effects of economic hedges that have not been designated as cash flow hedges, ineffectiveness on cash flow hedges, and trading activity on NRG's statement of operations. These amounts are included within operating revenues and cost of operations.

	Three months ended March 31,
	2012			2011
	(In millions)
Unrealized mark-to-market results
Reversal of previously recognized unrealized gains on settled positions related to economic hedges	$	(41	)	$	(2	)
Reversal of loss positions acquired as part of the Reliant Energy and Green Mountain Energy acquisitions	14			41
Net unrealized (losses)/gains on open positions related to economic hedges	(137		)	91
(Losses)/gains on ineffectiveness associated with open positions treated as     cash flow hedges	(1		)	3
Total unrealized mark-to-market (losses)/gains for economic hedging activities	(165		)	133
Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity	(30		)	14
Net unrealized gains on open positions related to trading activity	28			—
Total unrealized mark-to-market (losses)/gains for trading activity	(2		)	14
Total unrealized (losses)/gains	$	(167	)	$	147

	Three months ended March 31,
	2012			2011
	(In millions)
Revenue from operations — energy commodities	$	38		$	13
Cost of operations	(205		)	134
Total impact to statement of operations	$	(167	)	$	147

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

For the three months ended March 31, 2012, the unrealized loss from open economic hedge positions was the result of a decrease in value of forward purchases of coal, due to decreases in forward coal prices along with a decrease in value of forward purchases and sales of natural gas and electricity, due to a decrease in forward power and gas prices and increases in Electric Reliability Council of Texas, or ERCOT, heat rates.

For the three months ended March 31, 2011, the unrealized gain from open economic hedge positions was the result of an increase in value of forward purchases and sales of natural gas, electricity and fuel due to an increase in forward power and gas prices.

Credit Risk Related Contingent Features

Certain of the Company's hedging agreements contain provisions that require the Company to post additional collateral if the counterparty determines that there has been deterioration in credit quality, generally termed “adequate assurance” under the agreements, or requires the Company to post additional collateral if there were a one notch downgrade in the Company's credit rating. The collateral required for contracts with adequate assurance clauses that are in a net liability position as of March 31, 2012, was $119 million. The collateral required for contracts with credit rating contingent features was $42 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 $45 million as of March 31, 2012.

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

21

Note 8 — Debt and Capital Leases

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

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

	March 31, 2012		December 31, 2011		Interest rate % (a)
	(In millions, except rates)
NRG Recourse Debt:
Senior notes, due 2021	$	1,200	$	1,200	7.875
Senior notes, due 2020	1,100		1,100		8.250
Senior notes, due 2019	800		800		7.625
Senior notes, due 2019	692		691		8.500
Senior notes, due 2018	1,200		1,200		7.625
Senior notes, due 2017	1,090		1,090		7.375
Term loan facility, due 2018	1,584		1,588		L+3.00
Indian River Power LLC, tax-exempt bonds, due 2040	57		57		6.000
Indian River Power LLC, tax-exempt bonds, due 2045	157		148		5.375
Dunkirk Power LLC, tax-exempt bonds, due 2042	59		59		5.875
Subtotal NRG Recourse Debt	7,939		7,933
NRG Non-Recourse Debt:
Ivanpah Financing:
Solar Partners I, due 2014 and 2033	351		290		1.126 - 3.991
Solar Partners II, due 2014 and 2038	377		314		1.116 - 4.195
Solar Partners VIII, due 2014 and 2038	321		270		1.381 - 4.256
NRG Peaker Finance Co. LLC, bonds, due 2019	191		190		L+1.07
Agua Caliente Solar, LLC, due 2037	233		181		2.730 - 3.256
NRG West Holdings LLC, term loan, due 2023	198		159		L+2.25 - 2.75
NRG Energy Center Minneapolis LLC, senior secured notes,    due 2013, 2017 and 2025	147		151		5.95 - 7.31
CVSR - High Plains Ranch II LLC, due 2037	138		—		0.61 - 0.68
South Trent Wind LLC, financing agreement, due 2020	75		75		L+2.50
Solar Power Partners - SPP Fund II/IIB LLC term loans, due 2017	17		17		L+3.50
Solar Power Partners - SPP Fund III LLC term loan, due 2024	42		42		L+3.50
NRG Solar Roadrunner LLC, due 2031	47		61		L+2.01
NRG Solar Blythe LLC, credit agreement, due 2028	27		27		L+2.50
Other	15		19		various
Subtotal NRG Non-Recourse Debt	2,179		1,796
Subtotal long-term debt	10,118		9,729
Capital leases:
Saale Energie GmbH, Schkopau capital lease, due 2021	103		103
Subtotal	10,221		9,832
Less current maturities	71		87
Total long-term debt and capital leases	$	10,150	$	9,745

(a) L+ equals LIBOR plus x%.

22

NRG Repowering Holdings LLC

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

On January 25, 2012, NRG Repowering entered into a Credit and Reimbursement Agreement which provides for a $10 million working capital facility that can be used for general corporate purposes or to issue letters of credit, and an $80 million letter of credit facility. Interest on the letters of credit accrues at 3.5% and on loans under the working capital facility at the London Inter-Bank Offered Rate, or LIBOR, plus 3.50%. The facility is secured by NRG Repowering's investments in GenConn Energy, LLC and South Trent Wind LLC, and matures January 25, 2015. As of March 31, 2012, NRG Repowering had issued $10 million letter of credit under the working capital facility and $80 million in letters of credit under the letter of credit facility.

Alpine Financing

On March 16, 2012, NRG, through its wholly-owned subsidiary, NRG Solar Alpine LLC, or Alpine, entered into a credit agreement with a group of lenders, or the Alpine Financing Agreement, for a $166 million construction loan that will convert to a term loan upon completion of the project and a $68 million cash grant loan. The construction loan has an interest rate of LIBOR plus an applicable margin of 2.50% and the cash grant loan has an interest rate of LIBOR plus an applicable margin of 2.25%. The term loan has an interest rate of LIBOR plus an applicable margin of 2.50%, which escalates 0.25% on the fifth anniversary of the term conversion. The term loan, which is secured by all the assets of Alpine, matures on the 10^th anniversary of the term conversion and amortizes based upon a predetermined schedule. The cash grant loan matures upon the earlier of the receipt of the cash grant or February 2013. The Alpine Financing Agreement also includes a letter of credit facility on behalf of Alpine of up to $37 million. Alpine pays an availability fee of 100% of the applicable margin on issued letters of credit. As of March 31, 2012, $2 million was outstanding under the construction loan, nothing was outstanding under the cash grant loans, and $18 million in letters of credit in support of the project were issued.

Also related to the Alpine Financing Agreement, on March 16, 2012, Alpine entered into a series of fixed for floating interest rate swaps for at least 85% of the outstanding term loan amount, intended to hedge the risks associated with floating interest rates. Alpine will pay its counterparty the equivalent of a 2.74% fixed interest payment on a predetermined notional value, and Alpine will receive quarterly the equivalent of a floating interest payment based on a one month LIBOR calculated on the same notional value through December 31, 2012 and based on a three month LIBOR from December 31, 2012 through the term loan maturity date. All interest rate swap payments by Alpine and its counterparty are made monthly through December 31, 2012, and quarterly thereafter and the LIBOR rate is determined in advance of each interest period. The original notional amount of the swap, which became effective March 31, 2012, and matures on December 31, 2029, was $3 million and will increase and amortize in proportion to the loan.

Roadrunner Financing

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

CVSR Financing

On March 9, 2012, NRG, through its wholly-owned subsidiary, High Plains Ranch II LLC, completed its first borrowing of $138 million under the CVSR Financing Agreement with the Federal Financing Bank. As of March 31, 2012, $138 million was outstanding under the loan.

23

Note 9 — Variable Interest Entities, or VIEs

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

GenConn Energy LLC — Through its subsidiary, NRG Connecticut Peaking Development LLC, NRG owns a 50% interest in GenConn, a limited liability company which owns and operates two200 MW peaking generation facilities in Connecticut at NRG's Devon and Middletown sites. NRG's maximum exposure to loss is limited to its equity investment, which was $131 million as of March 31, 2012.

Sherbino I Wind Farm LLC — NRG owns a 50% interest in Sherbino, a joint venture with BP Wind Energy North America Inc. NRG's maximum exposure to loss is limited to its equity investment, which was $98 million as of March 31, 2012.

Texas Coastal Ventures, LLC— NRG owns a 50% interest in Texas Coastal Ventures, a joint venture with Hilcorp Energy I, L.P., through its subsidiary Petra Nova LLC. NRG's maximum exposure to loss is limited to its equity investment, which was $49 million as of March 31, 2012.

Note 10 — Changes in Capital Structure

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

	Issued	Treasury		Outstanding
Balance as of December 31, 2011	304,183,720	(76,664,199	)	227,519,521
Shares issued under LTIP	89,563	—		89,563
Shares issued under ESPP	—	76,423		76,423
Balance as of March 31, 2012	304,273,283	(76,587,776	)	227,685,507

Employee Stock Purchase Plan —On April 25, 2012, NRG shareholders approved an increase of 1,000,000 shares available for issuance under the NRG Energy, Inc. Employee Stock Purchase Plan, or ESPP. Subsequent to this approval, 1,100,928 shares of treasury stock are available for issuance under the ESPP.

24

Note 11 — Loss Per Share

Basic and diluted loss per common share is computed by dividing the net loss less accumulated preferred stock dividends by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the period are weighted for the portion of the period that they were outstanding.

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

	Three months ended March 31,
(In millions, except per share data)	2012			2011
Basic and diluted loss per share attributable to NRG common stockholders
Numerator:
Net loss attributable to NRG Energy, Inc.	$	(207	)	$	(260	)
Preferred stock dividends	(2		)	(2		)
Net loss attributable to NRG Energy, Inc. available to common stockholders	$	(209	)	$	(262	)
Denominator:
Weighted average number of common shares outstanding	228			247
Basic and diluted loss per share:
Net loss attributable to NRG Energy, Inc.	$	(0.92	)	$	(1.06	)

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 per share:

	Three months ended March 31,
(In millions of shares)	2012	2011
Equity compensation plans	9	7
Embedded derivative of 3.625% redeemable perpetual preferred stock	16	16
Total	25	23

25

Note 12 — Segment Reporting

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

(In millions)			Conventional Power Generation
Three months ended March 31, 2012	Retail		Texas(a)			Northeast(b)			South Central			West			Other (c)		Alternative Energy(d)			Corporate			Elimination			Total
Operating revenues	$	1,166	$	458		$	148		$	173		$	42		$	94	$	22		$	3		$	(244	)	$	1,862
Depreciation and amortization	41		114			32			23			2			4		11			3			—			230
Equity in earnings/(losses) of unconsolidated affiliates	—		—			5			—			(2		)	3		2			—			—			8
Income/(loss) before income taxes	7		(74		)	(43		)	(30		)	(14		)	10		(11		)	(171		)	—			(326		)
Net income/(loss) attributable to NRG Energy, Inc.	$	7	$	(74	)	$	(43	)	$	(30	)	$	(14	)	$	8	$	(12	)	$	(49	)	$	—		$	(207	)
Total assets	$	2,280	$	13,681		$	1,923		$	1,270		$	661		$	1,073	$	4,095		$	20,541		$	(16,994	)	$	28,530

(a) Includes inter-segment revenues of $182 million.

(b) Includes inter-segment revenues of $35 million.

(c) Includes inter-segment revenues of $20 million.

(d) Includes inter-segment revenues of $4 million.

(In millions)			Conventional Power Generation
Three months ended March 31, 2011	Retail		Texas(e)		Northeast			South Central		West		Other(f)		Alternative Energy			Corporate(g)			Elimination			Total
Operating revenues	$	1,126	$	523	$	226		$	189	$	40	$	84	$	9		$	1		$	(203	)	$	1,995
Depreciation and amortization	26		115		29			20		2		3		6			4			—			205
Equity in earnings/(losses) of unconsolidated affiliates	—		—		2			—		—		4		(8		)	—			—			(2		)
Income/(loss) before income taxes	294		27		(34		)	12		13		10		(18		)	(669		)	—			(365		)
Net income/(loss) attributable to NRG Energy, Inc.	$	297	$	27	$	(34	)	$	12	$	13	$	8	$	(18	)	$	(565	)	$	—		$	(260	)

(e)    Includes inter-segment revenues of $196 million.

(f)    Includes inter-segment revenues of $6 million.

(g)    Includes impairment charge on investment of $481 million and loss on debt extinguishment of $28 million.

26

Note 13 — Income Taxes

Effective Tax Rate

The income tax provision consisted of the following:

	Three months ended March 31,
(In millions except otherwise noted)	2012			2011
Income tax benefit	$	(120	)	$	(105	)
Effective tax rate	36.8		%	28.8		%

For the three months ended March 31, 2012, NRG recorded an income tax benefit on a pre-tax loss of $326 million. NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the generation of ITCs from the Company's Agua Caliente solar project in Arizona.

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.

Uncertain tax benefits

As of March 31, 2012, NRG has recorded a non-current tax liability of $62 million for uncertain tax benefits from positions taken on various state tax returns, including accrued interest. NRG has accrued interest related to these uncertain tax benefits of $1 million for the three months ended March 31, 2012, and has accrued $13 million of interest and penalties since adoption. The Company recognizes interest and penalties related to uncertain tax benefits in income tax expense.

The Company will continue to be under examination by various state and foreign tax jurisdictions for multiple years.

Tax Receivable and Payable

As of March 31, 2012, NRG recorded a current domestic tax receivable of $31 million, of which $18 million is related to property tax refunds as a result of the New York State Empire Zone program and $11 million relates to Federal income tax refunds for prior year tax return filings. As of March 31, 2012, NRG has a current tax payable of $20 million that represents a tax liability due for domestic state taxes of $18 million, as well as foreign taxes payable of $2 million.

27

Note 14 — 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, 2012, 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, Contingencies and related guidance, NRG records reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. In addition, legal costs are expensed as incurred. Management has assessed each of the following matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, the Company is unable to predict the outcome of these legal proceedings or reasonably estimate the scope or amount of any associated costs and potential liabilities. As additional information becomes available, management adjusts its assessment and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of the Company's liabilities and contingencies could be at amounts that are different from its currently recorded reserves and that such difference could be material.

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

California Department of Water Resources

This matter concerns, among other contracts and other defendants, the California Department of Water Resources, or CDWR, and its wholesale power contract with subsidiaries of WCP (Generation) Holdings, Inc., or WCP. The case originated with a February 2002 complaint filed by the State of California alleging that many parties, including WCP subsidiaries, overcharged the State of California. For WCP, the alleged overcharges totaled approximately $940 million for 2001 and 2002. The complaint demanded that the 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 FERC's review of the contracts at issue, FERC could not rely on the Mobile-Sierra standard presumption of just and reasonable rates, where such contracts were not reviewed by the FERC with full knowledge of the then existing market conditions. WCP and others sought review by the U.S. Supreme Court. WCP's appeal was not selected, but instead held by the Supreme Court. In the appeal that was selected by the Supreme Court, on June 26, 2008, the Supreme Court ruled: (i) that the Mobile-Sierra public interest standard of review applied to contracts made under a seller's market-based rate authority; (ii) that the public interest “bar” required to set aside a contract remains a very high one to overcome; and (iii) that the Mobile-Sierra presumption of contract reasonableness applies when a contract is formed during a period of market dysfunction unless (a) such market conditions were caused by the illegal actions of one of the parties or (b) the contract negotiations were tainted by fraud or duress. In this related case, the U.S. Supreme Court affirmed the Ninth Circuit's decision agreeing that the case should be remanded to the FERC to clarify the FERC's 2003 reasoning regarding its rejection of the original complaint relating to the financial burdens under the contracts at issue and to alleged market manipulation at the time these contracts were formed. As a result, the U.S. Supreme Court then reversed and remanded the WCP CDWR case to the Ninth Circuit for treatment consistent with its June 26, 2008, decision in the related case. On October 20, 2008, the Ninth Circuit asked the parties in the remanded CDWR case, including WCP and the FERC, whether that Court should answer a question the U.S. Supreme Court did not address in its June 26, 2008, decision; whether the Mobile-Sierra doctrine applies to a third-party that was not a signatory to any of the wholesale power contracts, including the CDWR contract, at issue in that case. Without answering that reserved question, on December 4, 2008, the Ninth Circuit vacated its prior opinion and remanded the WCP CDWR case back to the FERC for proceedings consistent with the U.S. Supreme Court's June 26, 2008, decision. On December 15, 2008, WCP and the other seller-defendants filed with the FERC a Motion for Order Governing Proceedings on Remand. On January 14, 2009, the Public Utilities Commission of the State of California, or CPUC, filed an Answer and Cross Motion for an Order Governing Procedures on Remand and on January 28, 2009, WCP and the other seller-defendants filed their reply. At this time, the FERC has not acted on remand.

28

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

As part of the 2006 acquisition of Dynegy's 50% ownership interest in WCP, WCP and NRG assumed responsibility for any risk of loss arising from this case, unless any such loss was deemed to have resulted from certain acts of gross negligence or willful misconduct on the part of Dynegy, in which case any such loss would be shared equally between WCP and Dynegy.

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

Louisiana Generating, LLC

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

On April 27, 2009, LaGen filed an objection in the Cajun Electric Cooperative Power, Inc.'s bankruptcy proceeding in the U.S. Bankruptcy Court for the Middle District of Louisiana to seek to prevent the bankruptcy from closing. LaGen also filed a complaint, or adversary proceeding, in the same bankruptcy proceeding, seeking a judgment that: (i) it did not assume liability from Cajun Electric for any claims or other liabilities under environmental laws with respect to Big Cajun II that arose, or are based on activities that were undertaken, prior to the closing date of the acquisition; (ii) it is not otherwise the successor to Cajun Electric with respect to environmental liabilities arising prior to the acquisition; and (iii) Cajun Electric and/or the Bankruptcy Trustee are exclusively liable for any of the violations alleged in the February 11, 2009 lawsuit to the extent that such claims are determined to have merit. On April 15, 2010, the bankruptcy court signed an order granting LaGen's stipulation of voluntary dismissal without prejudice of the adversary proceeding. The bankruptcy proceeding has since closed.

29

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 thereafter submitted additional briefing on emerging jurisprudence from other jurisdictions touching on the issues at stake in the lawsuit. Having not ruled on the motion to dismiss, 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 November 2, 2011, the court heard oral argument on three motions for summary judgment. On December 1, 2011, the court issued an order denying two of LaGen's motions for summary judgment addressing potential legal defenses to CAA liability. In the same order, the court also granted, in part, the U.S. DOJ's motion for summary judgment on its successor liability theory. The court held that LaGen could be found to have assumed liability for alleged PSD violations under the terms of the agreement through which LaGen acquired Big Cajun II in 2000, but ruled that the facts necessary to determine whether any such liabilities were actually assumed must be determined at a liability-phase trial, if necessary. In its December 1, 2011 decision, the court also ruled that any potential civil penalties would not be available for the periods prior to the five year period preceding the filing of the lawsuit on February 11, 2009.

Three additional motions for summary judgment and multiple motions in limine, including motions that could result in dismissal of the government's claims before trial if resolved in LaGen's favor, remain pending before the court; some of these motions were argued on March 21 and 22, 2012. On January 17, 2012, LaGen filed a demand for a jury trial. On January 20, 2012, the court scheduled a liability-phase trial for October 15, 2012, should the case proceed to that stage, and a remedy-phase trial set to occur at a later date to be determined in the event of an adverse decision in a liability-phase trial. Because of the inherent uncertainty of litigation, including the fact that no determination of liability has yet been made by the Court, NRG cannot predict the impact, at this time, that this matter may have on the Company's business, results of operations, financial position, or cash flows.

In a related matter, soon after the filing of the above referenced U.S. DOJ lawsuit, LaGen sought insurance coverage from its insurance carrier, Illinois Union Insurance Company, or ILU. ILU denied coverage and thereafter LaGen filed a lawsuit (which was consolidated with a prior suit filed by ILU) seeking a declaration that ILU must provide coverage to LaGen for the defense costs incurred in defending the U.S. DOJ lawsuit.  LaGen and ILU both filed motions for summary judgment and on January 30, 2012, the court issued an order granting LaGen's motion finding that ILU has a duty to defend LaGen. On February 27, 2012, ILU filed a motion for new trial or, in the alternative, for an interlocutory appeal. LaGen filed an opposition to this motion on March 19, 2012.

Wise v. Energy Plus Holdings, LLC

On October 18, 2011, plaintiff filed a purported class action lawsuit on behalf of New York consumers against Energy Plus in the U.S. District Court for the Southern District of New York.  Claiming statutory damages in excess of $5 million, the plaintiff alleges violations of New York business laws as well as unjust enrichment. Specifically, the plaintiff claims that Energy Plus misrepresents that its rates are competitive in the market; fails to disclose that its rates are substantially higher than those in the market and that Energy Plus has engaged in deceptive practices in its marketing of energy services. Plaintiff seeks that this matter be certified as a class action, with treble damages, interest, costs, attorneys' fees, and any other relief that the court deems just and proper. On January 11, 2012, plaintiff filed an amended complaint in which they added another co-plaintiff, made additional claims as to how they became customers of Energy Plus and made some additional allegations as to alleged representations on the Energy Plus website. On February 1, 2012, Energy Plus filed a motion to dismiss the amended complaint. On March 23, 2012, an order was entered dismissing the plaintiffs' claims for unjust enrichment and that Energy Plus's disclosure of its variable rate is inadequate. The purported class action is now limited to plaintiffs' claims of potential misrepresentation in Energy Plus's advertising of its products.

30

Note 15 — Regulatory Matters

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

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

California — On May 4, 2010, in Southern California Edison Company v. FERC, the U.S. Court of Appeals for the D.C. Circuit vacated FERC's acceptance of station power rules for the California Independent System Operator, or CAISO, market, and remanded the case for further proceedings at FERC. On August 30, 2010, FERC issued an Order on Remand effectively disclaiming jurisdiction over how the states impose retail station power charges. Due to reservation-of-rights language in the California utilities' state-jurisdictional station power tariffs, FERC's ruling arguably requires California generators to pay state-imposed retail charges back to the date of enrollment by the facilities in the CAISO's station period program (February 1, 2009, for the Company's Encina and El Segundo facilities; March 1, 2009, for the Company's Long Beach facility). On February 28, 2011, FERC issued an order denying rehearing. The Company, together with other generators, filed an appeal and briefing of the case is currently underway. On November 18, 2011, Southern California Edison Company filed with the CPUC, seeking authorization to begin charging generators station power charges, and to assess such charges retroactively, which the Company and other generators have challenged. The Company has filed a protest with the CPUC objecting to Southern California Edison's filing. The Company believes it has established an appropriate reserve.

Retail (Replacement Reserve)—On November 14, 2006, Constellation Energy Commodities Group, or Constellation, filed a complaint with the PUCT alleging that ERCOT misapplied the Replacement Reserve Settlement, or RPRS, Formula contained in the ERCOT protocols from April 10, 2006, through September 27, 2006.  Specifically, Constellation disputed approximately $4 million in under-scheduling charges for capacity insufficiency asserting that ERCOT applied the wrong protocol.  Retail Electric Providers, or REPS, other market participants, ERCOT, and PUCT staff opposed Constellation's complaint.  On January 25, 2008, the PUCT entered an order finding that ERCOT correctly settled the capacity insufficiency charges for the disputed dates in accordance with ERCOT protocols and denied Constellation's complaint.  On April 9, 2008, Constellation appealed the PUCT order to the Civil District Court of Travis County, Texas and on June 19, 2009, the court issued a judgment reversing the PUCT order, finding that the ERCOT protocols were in irreconcilable conflict with each other.  Under the PUCT ordered formula, Qualified Scheduling Entities, or QSEs, who under-scheduled capacity within any of ERCOT's four congestion zones were assessed under-scheduling charges which defrayed the costs incurred by ERCOT for RPRS that would otherwise be spread among all load-serving QSEs.  Under the Court's decision, all RPRS costs would be assigned to all load-serving QSEs based upon their load ratio share without assessing any separate charge to those QSEs who under-scheduled capacity.  If under-scheduling charges for capacity insufficient QSEs were not used to defray RPRS costs, REPS's share of the total RPRS costs allocated to QSEs would increase.  On July 20, 2009, REPS filed an appeal to the Third Court of Appeals in Travis County, Texas, thereby staying the effect of the trial court's decision.  On October 6, 2010, the parties argued the appeal before the Court of Appeals for the Third District in Austin, Texas.  On September 28, 2011, the Court of Appeals reversed the trial court decision, reinstating the PUCT's order, consistent with REPS' position. On January 13, 2012, Constellation filed a Petition for Review in the Supreme Court of Texas asking the Court to grant review of and reverse the Court of Appeals decision. The Texas Supreme Court requested that a response to Constellation's petition be filed. The response is due May 16, 2012.   

31

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., or MISO, and PJM Interconnection, L.L.C., or PJM. In order to temporarily compensate the transmission owners for revenue lost as a result of the elimination of the through-and-out transmission rates, 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. The Order on Initial Decision also directed that the two Regional Transmission Organizations, or RTOs, and their respective transmission owners submit further compliance filings, which were filed on August 19, 2010. FERC has not yet ruled on those compliance filings.

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 believes it has established an appropriate reserve.

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

32

Note 16 — Environmental Matters

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

Environmental Capital Expenditures

Based on current rules, technology and plans as well as preliminary plans based on proposed rules, NRG has estimated that environmental capital expenditures from 2012 through 2016 to meet NRG's regulatory environmental commitments will be approximately $553 million. These costs are primarily associated with mercury controls to satisfy the Mercury and Air Toxics Standards, or MATS, on the Company's Big Cajun II, W.A. Parish and Limestone facilities and a number of intake modification projects across the fleet under state or proposed federal 316(b) rules. NRG continues to explore cost effective compliance alternatives to reduce costs. While this estimate reflects anticipated schedules and controls related to the proposed 316(b) Rule, the full impact on the scope and timing of environmental retrofits from any new or revised regulations cannot be determined until these rules are final and any legal challenges are reviewed. However, NRG believes it is positioned to meet more stringent environmental regulations through its planned capital expenditures, existing controls, and increasing generation from renewable resources.

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

Northeast Region

In January 2006, NRG's Indian River Operations, Inc. received a letter of informal notification from Delaware Department of Natural Resources and Environmental Control, or DNREC, stating that it may be a potentially responsible party with respect to Burton Island Old Ash Landfill, a historic captive landfill located at the Indian River facility. On October 1, 2007, NRG signed an agreement with DNREC to investigate the site through the Voluntary Clean-up Program. On February 4, 2008, DNREC issued findings that no further action is required in relation to surface water and that a previously planned shoreline stabilization project would satisfactorily address shoreline erosion. The landfill itself will require a further Remedial Investigation and Feasibility Study to determine the type and scope of any additional work required. Until the Remedial Investigation and Feasibility Study is approved, the Company is unable to predict the impact of any required remediation. On May 29, 2008, DNREC requested that NRG's Indian River Operations, Inc. participate in the development and performance of a Natural Resource Damage Assessment, or NRDA, at the Burton Island Old Ash Landfill. NRG is currently working with DNREC and other trustees to close out the assessment phase.

South Central Region

On 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 14, Commitments and Contingencies- Louisiana Generating, LLC.

33

Note 17 — Condensed Consolidating Financial Information

As of March 31, 2012, the Company had outstanding $6.1 billion of Senior Notes due from 2017 - 2021, as shown in Note 8, Debt and Capital Leases. These Senior Notes are guaranteed by certain of NRG's current and future wholly-owned domestic subsidiaries, or guarantor subsidiaries. The non-guarantor subsidiaries include all of NRG's foreign subsidiaries and certain domestic subsidiaries.

Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of March 31, 2012:

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

34

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.

35

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Three Months Ended March 31, 2012

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations(a)			Consolidated Balance
	(In millions)
Operating Revenues
Total operating revenues	$	1,778		$	101		$	—		$	(17	)	$	1,862
Operating Costs and Expenses
Cost of operations	1,522			60			6			(15		)	1,573
Depreciation and amortization	214			13			3			—			230
Selling, general and administrative	132			10			81			(2		)	221
Development costs	—			—			8			—			8
Total operating costs and expenses	1,868			83			98			(17		)	2,032
Operating (Loss)/Income	(90		)	18			(98		)	—			(170		)
Other Income/(Expense)
Equity in earnings/(losses) of consolidated subsidiaries	6			(2		)	(20		)	16			—
Equity in (losses)/earnings of unconsolidated affiliates	(2		)	10			—			—			8
Impairment charge on investment	(1		)	—			—			—			(1		)
Other income, net	—			1			1			—			2
Interest expense	(5		)	(14		)	(146		)	—			(165		)
Total other (expense)/income	(2		)	(5		)	(165		)	16			(156		)
(Loss)/Income Before Income Taxes	(92		)	13			(263		)	16			(326		)
Income tax benefit	(28		)	(36		)	(56		)	—			(120		)
Net (Loss)/Income	(64		)	49			(207		)	16			(206		)
Less: Net income attributable to noncontrolling interest	—			1			—			—			1
Net (Loss)/Income attributable to NRG Energy, Inc.	$	(64	)	$	48		$	(207	)	$	16		$	(207	)

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

36

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE (LOSS)/INCOME

For the Three Months Ended March 31, 2012

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)			Eliminations(a)		Consolidated Balance
	(In millions)
Net (Loss)/ Income	$	(64	)	$	49	$	(207	)	$	16	$	(206	)
Other comprehensive (loss)/income, net of tax
Unrealized (loss)/gain on derivatives, net	(13		)	7		(3		)	—		(9		)
Foreign currency translation adjustments, net	—			6		—			—		6
Other comprehensive (loss)/income	(13		)	13		(3		)	—		(3		)
Comprehensive (loss)/income	(77		)	62		(210		)	16		(209		)
Less: Comprehensive income attributable to noncontrolling interest	—			1		—			—		1
Comprehensive (loss)/income attributable to NRG Energy, Inc.	(77		)	61		(210		)	16		(210		)
Dividends for preferred shares	—			—		2			—		2
Comprehensive (loss)/income available for common stockholders	$	(77	)	$	61	$	(212	)	$	16	$	(212	)

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

37

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

March 31, 2012

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations(a)			Consolidated Balance
	(In millions)
ASSETS
Current Assets
Cash and cash equivalents	$	53		$	90		$	871		$	—		$	1,014
Funds deposited by counterparties	199			—			—			—			199
Restricted cash	9			179			29			—			217
Accounts receivable, net	669			47			—			—			716
Inventory	383			9			—			—			392
Derivative instruments	5,150			—			—			—			5,150
Cash collateral paid in support of energy risk management activities	498			—			—			—			498
Prepayments and other current assets	137			78			57			—			272
Total current assets	7,098			403			957			—			8,458
Net property, plant and equipment	10,326			3,992			76			(18		)	14,376
Other Assets
Investment in subsidiaries	327			119			16,196			(16,642		)	—
Equity investments in affiliates	31			612			—			—			643
Notes receivable – affiliate and capital leases, less current portion	1			369			167			(167		)	370
Goodwill	1,886			—			—			—			1,886
Intangible assets, net	1,264			84			30			(38		)	1,340
Nuclear decommissioning trust fund	456			—			—			—			456
Derivative instruments	649			—			—			—			649
Other non-current assets	59			81			212			—			352
Total other assets	4,673			1,265			16,605			(16,847		)	5,696
Total Assets	$	22,097		$	5,660		$	17,638		$	(16,865	)	$	28,530
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	—		$	56		$	15		$	—		$	71
Accounts payable	(1,419		)	495			2,004			—			1,080
Derivative instruments	4,780			23			21			—			4,824
Deferred income taxes	464			(39		)	(333		)	—			92
Cash collateral received in support of energy risk management activities	199			—			—			—			199
Accrued expenses and other current liabilities	392			27			200			—			619
Total current liabilities	4,416			562			1,907			—			6,885
Other Liabilities
Long-term debt and capital leases	273			2,394			7,650			(167		)	10,150
Nuclear decommissioning reserve	340			—			—			—			340
Nuclear decommissioning trust liability	279			—			—			—			279
Deferred income taxes	986			231			83			—			1,300
Derivative instruments	652			56			—			—			708
Out-of-market commodity contracts	201			6			—			(31		)	176
Other non-current liabilities	553			141			116			—			810
Total non-current liabilities	3,284			2,828			7,849			(198		)	13,763
Total liabilities	7,700			3,390			9,756			(198		)	20,648
3.625% convertible perpetual preferred stock	—			—			249			—			249
Stockholders’ Equity	14,397			2,270			7,633			(16,667		)	7,633
Total Liabilities and Stockholders’ Equity	$	22,097		$	5,660		$	17,638		$	(16,865	)	$	28,530

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

38

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2012

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations(a)			Consolidated Balance
	(In millions)
Cash Flows from Operating Activities
Net (loss)/income	$	(64	)	$	49		$	(207	)	$	16		$	(206	)
Adjustments to reconcile net (loss)/income to net cash provided/(used) by operating activities:
Distributions and equity in losses/(earnings) of unconsolidated affiliates and consolidated subsidiaries	9			(5		)	(17		)	13			—
Depreciation and amortization	214			13			3			—			230
Provision for bad debts	7			—			—			—			7
Amortization of nuclear fuel	6			—			—			—			6
Amortization of financing costs and debt discount/premiums	—			2			6			—			8
Amortization of intangibles and out-of-market commodity contracts	42			—			—			—			42
Changes in deferred income taxes and liability for uncertain tax benefits	(29		)	(44		)	(56		)	—			(129		)
Changes in nuclear decommissioning trust liability	8			—			—			—			8
Changes in derivative instruments	186			—			1			—			187
Changes in collateral deposits supporting energy risk management activities	(187		)	—			—			—			(187		)
Cash provided/(used) by changes in other working capital	104			33			(147		)	(32		)	(42		)
Net Cash Provided/(Used) by Operating Activities	296			48			(417		)	(3		)	(76		)
Cash Flows from Investing Activities
Intercompany loans to subsidiaries	(201		)	—			108			93			—
Capital expenditures	(69		)	(554		)	(16		)	—			(639		)
Increase in restricted cash, net	(1		)	(19		)	—			—			(20		)
Decrease in restricted cash - U.S. DOE projects	—			71			24			—			95
Increase in notes receivable	—			(7		)	—			—			(7		)
Investments in nuclear decommissioning trust fund securities	(126		)	—			—			—			(126		)
Proceeds from sales of nuclear decommissioning trust fund securities	119			—			—			—			119
Proceeds from renewable energy grants	—			28			—			—			28
Other	2			4			1			—			7
Net Cash (Used)/Provided by Investing Activities	(276		)	(477		)	117			93			(543		)
Cash Flows from Financing Activities
Proceeds from intercompany loans	—			(108		)	201			(93		)	—
Payment of dividends to preferred stockholders	—			—			(2		)	—			(2		)
Payments of intercompany dividends	—			(3		)	—			3			—
Net payments for settlement of acquired derivatives that include financing elements	(20		)	—			—			—			(20		)
Proceeds from issuance of long-term debt	9			406			—			—			415
Sale proceeds and other contributions from noncontrolling interest in subsidiaries	—			178			—			—			178
Payment of debt issuance costs	—			(10		)	—			—			(10		)
Payments for short and long-term debt	—			(30		)	(4		)	—			(34		)
Net Cash (Used)/Provided by Financing Activities	(11		)	433			195			(90		)	527
Effect of exchange rate changes on cash and cash equivalents	—			1			—			—			1
Net Increase/(Decrease) in Cash and Cash Equivalents	9			5			(105		)	—			(91		)
Cash and Cash Equivalents at Beginning of Period	44			85			976			—			1,105
Cash and Cash Equivalents at End of Period	$	53		$	90		$	871		$	—		$	1,014

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

39

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Three Months Ended March 31, 2011

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

40

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE (LOSS)/INCOME

For the Three Months Ended March 31, 2011

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)			Eliminations(a)		Consolidated Balance
	(In millions)
Net (Loss)/Income	$	(67	)	$	4	$	(260	)	$	63	$	(260	)
Other comprehensive (loss)/income, net of tax
Unrealized (loss)/gain on derivatives, net	(86		)	3		(69		)	70		(82		)
Foreign currency translation adjustments, net	—			12		—			—		12
Defined benefit plan	1			—		—			—		1
Other comprehensive (loss)/income	(85		)	15		(69		)	70		(69		)
Comprehensive (loss)/income attributable to NRG Energy, Inc.	(152		)	19		(329		)	133		(329		)
Dividends for preferred shares	—			—		2			—		2
Comprehensive (loss)/income available for common stockholders	$	(152	)	$	19	$	(331	)	$	133	$	(331	)

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

41

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

December 31, 2011

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

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

42

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2011

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations(a)			Consolidated Balance
	(In millions)
Cash Flows from Operating Activities
Net (loss)/income	$	(67	)	$	4		$	(260	)	$	63		$	(260	)
Adjustments to reconcile net (loss)/income to net cash provided/(used) 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 commodity 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 derivative instruments	(130		)	—			—			—			(130		)
Changes in collateral deposits supporting energy risk management activities	176			—			—			—			176
Impairment charge on investment	481			—			—			—			481
Cash provided/(used) 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
Investments in nuclear decommissioning trust fund securities	(105		)	—			—			—			(105		)
Proceeds from sales of nuclear decommissioning trust fund securities	95			—			—			—			95
Other	9			(5		)	(10		)	—			(6		)
Net Cash (Used)/Provided 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 payment for settlement of acquired derivatives that include financing elements	(17		)	—			—			—			(17		)
Proceeds from issuance of long-term debt	66			20			1,200			—			1,286
Payment of debt issuance and hedging costs	—			(2		)	(6		)	—			(8		)
Payments for short and long-term debt	—			(6		)	(1,355		)	—			(1,361		)
Other	—			(1		)	1			—			—
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.

43

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, 2012, and 2011. Also refer to NRG's Annual Report on Form 10-K for the year ended December 31, 2011, or 2011 Form 10-K, which includes detailed discussions of various items impacting the Company's business, results of operations and financial condition, including: Introduction and Overview section which provides a description of NRG's business segments; Strategy section; Business Environment section, including how regulation, weather, and other factors affect NRG's business; and Critical Accounting Policies and Estimates section. As described in Note 12, Segment Reporting, NRG updated its segment structure to reflect how management currently makes its financial decisions and allocates resources, based on the Retail businesses, conventional power generation, alternative energy businesses and corporate activities.

The discussion and analysis below has been organized as follows:

• Executive summary, including introduction and overview, business strategy, and changes to the business environment during the period including 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.

44

Executive Summary

Introduction and Overview

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

NRG's Business Strategy

NRG's business strategy is intended to maximize stockholder value through the production and sale of safe, reliable and affordable power to its customers in the markets served by the Company, while aggressively positioning the Company to meet the market's increasing demand for sustainable and low carbon energy solutions. This strategy is designed to enhance the Company's core business of competitive power generation and mitigate the risk of declining power prices. The Company expects to become a leading provider of sustainable energy solutions that promotes national energy security, while utilizing the Company's Retail businesses to complement and advance both initiatives.

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

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

45

Environmental Matters

Environmental Regulatory Landscape

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

Air — The U.S. EPA released the Cross-State Air Pollution Rule, or CSAPR, on July 7, 2011, with additional proposed updates on October 6, 2011. CSAPR was scheduled to replace the Clean Air Interstate Rule, or CAIR, on January 1, 2012. It was designed to bring states into attainment with PM 2.5 and ozone NAAQS, reducing SO₂ and NO_x emissions from power plants. The U.S. Court of Appeals for the District of Columbia Circuit stayed the rule on December 30, 2011, pending resolution of the numerous petitions for judicial review and leaving CAIR in effect during the stay. On February 8, 2012, the U.S. EPA finalized the incremental state allowance budgets and resulting company allocations proposed in October 2011 and added additional allowance in certain states under the Direct Final Rule. NRG benefited from both rounds of allocation increases. The Company is unable to predict the final outcome of the court proceeding. There is no material impact to NRG related to the stay.

On February 16, 2012, the U.S. EPA finalized MATS, to control emissions of hazardous air pollutants from coal and oil fired electric generating units. Requirements include meeting the standards for mercury, acid gases, and certain metals (such as particulate matter) by April 16, 2015 on a plantwide basis with the potential for a one year extension. NRG does not anticipate any plant impairments or capital expenditures beyond the current environmental capital expenditures schedule.

On March 8, the EPA affirmed the continued use of modified trigger levels through 2016 for GHG emissions in the Tailoring Rule. This rule maintains the current level at which projects must be permitted. While most repowering projects still trigger the permitting, the higher limit provides relief to smaller projects like the installation of back-end controls to meet other regulations.

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

Regulatory Matters

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

NRG's operations within the ERCOT footprint are not subject to rate regulation by the FERC, as they are deemed to operate solely within the ERCOT market and not in interstate commerce. These operations are subject to regulation by PUCT, as well as to regulation by the NRC with respect to the Company's ownership interest in STP.

Texas Region

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

46

ERCOT System-Wide Offer Caps — On April 12, 2012, the PUCT issued two proposed rulemakings relating to resource adequacy concerns. The first rulemaking proposes to raise the current ERCOT system-wide energy and ancillary service offer cap from $3,000 to $4,500/MWh beginning August 1, 2012. The second rulemaking proposes to raise the system-wide offer cap on June 1, 2013 to $5,000/MWh, escalating to $9,000/MWh on June 1, 2015. The ERCOT ISO is expected to shift the Power Balance Penalty Curve, or PBPC, to match these offer cap levels. An increase in the system-wide offer cap could have a material impact on NRG's retail and wholesale operations. Over the past several months, at the urging of the PUCT, the ERCOT ISO has implemented a number of measures intended to ensure that prompt energy prices accurately reflect supply scarcity conditions, such as requiring energy from reliability services (such as responsive reserves and reliability unit commitments) be offered at the system-wide offer cap, implementing floor prices during the deployment of non-spinning reserve services, and shifting 500 MWs of non-spinning reserves to responsive reserves procurement by the ISO.

Northeast Region

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

New York

New Financial Reporting Rules in New York —On March 23, 2012, the New York Public Service Commission, or NYPSC, issued an order addressing its policy of applying “lightened” regulation to wholesale generators. The order proposed to subject wholesale generators, which would include NRG entities operating in New York, to more stringent financial reporting rules, including a requirement for generators to make an annual submission of “receipts and expenditures” to the NYPSC. Comments on the proposed financial reporting forms are due to the NYPSC by May 29, 2012.

Dunkirk Power LLC Mothball Notice —On March 14, 2012, Dunkirk Power LLC filed a notice with the New York Department of Public Service, or DPS, of its intent to mothball the Dunkirk facility no later than September 10, 2012.  The effects of the mothball on electric system reliability will be reviewed by the DPS.  The Company expects that the proposed mothball may have a negative impact on the reliability of the New York transmission system and that portions of the Dunkirk facility may be retained for reliability purposes via a non-market compensation arrangement. 

CFTC — Dodd-Frank Act Developments

On April 27, 2012, the CFTC published its final rules for the definitions of “swap dealer,” “major swap participant” and “eligible contract participant” and for commodity options under the Dodd-Frank Wall Street Reform and Consumer Protection Act.  The Company is reviewing these rules and evaluating whether any of them may apply to its business.

Changes in Accounting Standards

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

47

Consolidated Results of Operations

The following table provides selected financial information for the Company:

	Three months ended March 31,
(In millions except otherwise noted)	2012			2011			Change %
Operating Revenues
Energy revenue (a)	$	434		$	598		(27	)%
Capacity revenue (a)	174			185			(6	)
Retail revenue	1,196			1,180			1
Mark-to-market for economic hedging activities	40			(1		)	N/A
Contract amortization	(31		)	(47		)	34
Other revenues (b)	49			80			(39	)
Total operating revenues	1,862			1,995			(7	)
Operating Costs and Expenses
Generation cost of sales (a)	448			556			(19	)
Retail cost of sales (a)	608			609			—
Mark-to-market for economic hedging activities	205			(134		)	(253	)
Contract and emissions credit amortization (c)	7			10			(30	)
Other cost of operations	305			283			8
Total cost of operations	1,573			1,324			19
Depreciation and amortization	230			205			12
Selling, general and administrative	221			143			55
Development costs	8			9			(11	)
Total operating costs and expenses	2,032			1,681			21
Operating (Loss)/Income	(170		)	314			(154	)
Other Income/(Expense)
Equity in earnings/(losses) of unconsolidated affiliates	8			(2		)	N/A
Impairment charge on investment	(1		)	(481		)	(100	)
Other income, net	2			5			(60	)
Loss on debt extinguishment	—			(28		)	(100	)
Interest expense	(165		)	(173		)	(5	)
Total other expense	(156		)	(679		)	(77	)
Loss before income tax expense	(326		)	(365		)	(11	)
Income tax benefit	(120		)	(105		)	14
Net Loss	(206		)	(260		)	(21	)
Less: Net income attributable to noncontrolling interest	1			—			100
Net Loss Attributable to NRG Energy, Inc.	$	(207	)	$	(260	)	(20	)
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)	2.74			4.11			(33	)%

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

(b) Includes unrealized trading gains and losses.

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

N/A - Not Applicable

48

Management’s discussion of the results of operations for the three months ended March 31, 2012, and 2011

Loss before income tax expense —The pre-tax loss of $326 million for the three months ended March 31, 2012, compared to a pre-tax loss of $365 million for the three months ended March 31, 2011, primarily reflects:

• in the current year, a decrease in operating income of $484 million as compared to the prior year period, which reflects:

◦ a decrease in net mark-to-market for economic hedging activities of $298 million and

◦ a $72 million decrease in Conventional Generation gross margin driven primarily by planned and unplanned outages as well as coal to gas switching and increased operating costs;

• offset in the prior year by:

◦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.

Net loss — The decrease in net loss of $54 million primarily reflects the drivers discussed above offset by an income tax benefit for the three months ended March 31, 2012, of $120 million, compared with an income tax benefit of $105 million in the comparable period.

Conventional Generation gross margin

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

	Three months ended March 31, 2012
	Conventional Generation
(In millions except otherwise noted)	Texas			Northeast			South Central			West			Other			Subtotal			Alternative Energy		Eliminations			Consolidated Total
Energy revenue	$	479		$	87		$	111		$	22		$	16		$	715		$	19	$	(300	)	$	434
Capacity revenue	18			57			61			29			17			182			—		(8		)	174
Other revenue	8			6			(4		)	(3		)	61			68			1		(20		)	49
Generation revenue	505			150			168			48			94			965			20		$	(328	)	$	657
Generation cost of sales	(192		)	(82		)	(114		)	(14		)	(46		)	(448		)	—
Generation gross margin	$	313		$	68		$	54		$	34		$	48		$	517		$	20
Business Metrics
MWh sold (in thousands)	8,324			1,296			4,127			371									426
MWh generated (in thousands)	6,320			900			4,263			371									426
Average on-peak market power prices ($/MWh) (a)(b)	$	25.32		$	35.87		$	24.41		$	27.22								N/A

49

	Three months ended March 31, 2011
	Conventional Generation
(In millions except otherwise noted)	Texas			Northeast			South Central			West			Other			Subtotal			Alternative Energy		Eliminations			Consolidated Total
Energy revenue	$	593		$	151		$	112		$	4		$	16		$	876		$	9	$	(287	)	$	598
Capacity revenue	5			74			61			29			18			187			—		(2		)	185
Other revenue	31			(1		)	3			3			50			86			—		(6		)	80
Generation revenue	629			224			176			36			84			1,149			9		$	(295	)	$	863
Generation cost of sales	(243		)	(145		)	(121		)	(2		)	(49		)	(560		)	—
Generation gross margin	$	386		$	79		$	55		$	34		$	35		$	589		$	9
Business Metrics
MWh sold (in thousands)	11,085			2,558			3,846			21									285
MWh generated (in thousands)	10,388			2,032			3,997			21									285
Average on-peak market power prices ($/MWh) (a)(b)	$	50.46		$	57.91		$	36.46		$	35.36								N/A
(a) Average on-peak market power prices calculated based on average settled market prices in the following zones: for Texas region, in ERCOT - Houston and ERCOT - North; for Northeast region, in NYISO - West, NYISO - New York City, ISO - NE - Mass Hub, PJM - West Hub and PJM - DPL; and for West region, in CAISO - NP15 and CAISO - SP15.
(b) Average on-peak market power prices for South Central region are calculated based on average day ahead market prices for "into Entergy" as published in the Platts Megawatt Daily report.
	Three months ended March 31,
Weather Metrics	Texas			Northeast			South Central			West
2012
CDDs (c)	157			—			77			—
HDDs (c)	686			3,047			1,113			1,416
2011
CDDs	137			—			9			2
HDDs	1,108			3,169			1,866			1,481
30 year average
CDDs	95			—			46			7
HDDs	1,132			3,127			1,649			1,434

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

50

Conventional Generation gross margin — decreased by $72 million, including intercompany sales, during the three months ended March 31, 2012, compared to the same period in 2011, due to:

Decrease in Texas region	$	(73	)
Decrease in Northeast region	(11		)
Decrease in South Central region	(1		)
Other (a)	13
	$	(72	)

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

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

Lower gross margin from a 36% decrease in coal generation which was driven by higher planned and unplanned outages	$	(29	)
Lower gross margin from a 51% decrease in nuclear generation which related primarily to an unplanned outage at STP	(24		)
Lower gross margin driven by lower average realized energy prices	(9		)
Decrease in unrealized trading activities	(13		)
Other	2
	$	(73	)

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

Lower gross margin from coal plants due to a 16% decrease in realized energy prices	$	(7	)
Lower gross margin from coal plants due to a 64% decrease in generation, resulting from the region's power generation switching from coal to gas plants due to continuing declines in gas prices	(12		)
Lower capacity revenue due to 19% lower hedged prices and slightly lower volumes	(16		)
Higher gross margin from an increase in the margins realized on certain load-serving contracts as a result of more favorable pricing, as well as the addition of intercompany sales under load contracts with Energy Plus	20
Other	4
	$	(11	)

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

Higher gross margin from higher utilization of gas generation due to lower gas prices and higher overall sales volumes	$	37
Lower gross margin from a decrease in coal generation, due to some of the region's power switching from coal to gas generation	(18		)
Lower gross margin from a decrease in average realized prices	(11		)
Other	(9		)
	$	(1	)

In addition to these decreases, gross margin in the West region remained flat compared to the prior year driven by:

Higher energy margin from increased run time at Encina driven by competitor's plant outages in the region	$	6
Decrease in unrealized trading activities	(6		)
	$	—

51

Retail gross margin

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

Selected Income Statement Data

	Three months ended March 31,
(In millions except otherwise noted)	2012		2011
Operating Revenues
Mass revenues	$	730	$	702
Commercial and Industrial revenues	441		448
Supply management revenues	26		30
Retail operating revenues (a)(b)	1,197		1,180
Retail cost of sales (c)	917		895
Retail gross margin	$	280	$	285
Business Metrics
Electricity sales volume — GWh
Mass	5,607		5,378
Commercial and Industrial (a)	6,512		6,191
Electricity sales volume — GWh
Texas	11,066		11,472
All other regions	1,053		97
Average retail customers count (in thousands, metered locations)
Mass	2,077		1,812
Commercial and Industrial (a)	96		78
Retail customers count (in thousands, metered locations)
Mass	2,087		1,819
Commercial and Industrial (a)	98		79
Weather Metrics
CDDs (d)	200		151
HDDs (d)	590		960

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

(b) Excludes eliminations of $1 million, representing sales from Retail to the Texas region for the three months ended March 31, 2012.

(c) Includes intercompany purchases of $289 million and $286 million, respectively.

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

52

• Retail gross margin — Retail gross margin decreased $5 million for the three months ended March 31, 2012, compared to the same period in 2011, driven by:

Acquisition of Energy Plus in September 2011	$	29
Unfavorable impact of lower volume from mild winter weather in Texas in 2012, as well as increased risk management activities	(25		)
Decrease from lower revenues due to lower pricing on C&I acquisitions and renewals consistent with competitive offers, partially offset by lower supply costs due to lower natural gas prices and by increased customer counts	(9		)
	$	(5	)

• Trends — Customer counts increased by approximately 31,000 since December 31, 2011, which was primarily due to expansion into new territories and marketing efforts. While cooling and heating degree days in both periods resulted in higher than normal customer usage, weather in 2011 was colder than in 2012. The weather resulted in higher customer usage of 2% and 11% in 2012 and 2011, respectively, when compared to ten-year normal weather. In addition, there were increases in Transmission and Distribution Service Provider rates for transition costs and tariff filings that will remain in effect for several years. These costs are passed through to Retail customers.

Alternative Energy gross margin

NRG's Alternative Energy business segment, which is comprised mainly of the solar and wind businesses, had gross margin of $20 million for the three months ended March 31, 2012, compared to gross margin of $9 million for the same period in 2011. The increase in gross margin primarily resulted in the addition of the Roadrunner facility, which began commercial operations in late 2011, the addition of the first two blocks of Agua Caliente, which reached commercial operations in January and February 2012, and an increase in gross margin from Distributed Solar.

Mark-to-market for Economic Hedging Activities

Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges and ineffectiveness on cash flow hedges. Total net mark-to-market results decreased by $298 million during the three months ended March 31, 2012, compared to the same period in 2011.

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

	Three months ended March 31, 2012
	Retail			Texas			Northeast			South Central			West			Alternative Energy		Elimination(a)			Total
	(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(2	)	$	(188	)	$	(2	)	$	10		$	1		$	—	$	62		$	(119	)
Net unrealized gains/(losses) on open positions related to economic hedges	6			141			—			(10		)	(7		)	3		26			159
Total mark-to-market gains/(losses) in operating revenues	$	4		$	(47	)	$	(2	)	$	—		$	(6	)	$	3	$	88		$	40
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	129		$	6		$	3		$	2		$	—		$	—	$	(62	)	$	78
Reversal of loss positions acquired as part of the Reliant Energy and Green Mountain Energy acquisitions	14			—			—			—			—			—		—			14
Net unrealized losses on open positions related to economic hedges	(176		)	(48		)	(13		)	(34		)	—			—		(26		)	(297		)
Total mark-to-market losses in operating costs and expenses	$	(33	)	$	(42	)	$	(10	)	$	(32	)	$	—		$	—	$	(88	)	$	(205	)

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

53

	Three months ended March 31, 2011
	Retail			Texas			Northeast			South Central			West		Alternative Energy		Elimination(a)			Total
	(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	—		$	(59	)	$	8		$	6		$	—	$	—	$	38		$	(7	)
Net unrealized (losses)/gains on open positions related to economic hedges	(2		)	(47		)	(6		)	2			4		—		55			6
Total mark-to-market (losses)/gains in operating revenues	$	(2	)	$	(106	)	$	2		$	8		$	4	$	—	$	93		$	(1	)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	45		$	1		$	(2	)	$	(1	)	$	—	$	—	$	(38	)	$	5
Reversal of loss positions acquired as part of the Reliant Energy and Green Mountain Energy acquisitions	41			—			—			—			—		—		—			41
Net unrealized gains/(losses) on open positions related to economic hedges	125			10			3			5			—		—		(55		)	88
Total mark-to-market gains/(losses) in operating costs and expenses	$	211		$	11		$	1		$	4		$	—	$	—	$	(93	)	$	134

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

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

For the three months ended March 31, 2012, the net losses on open positions were due to a decrease in forward coal and power prices and increases in ERCOT heat rates.

For the three months ended March 31, 2011, the gains on open positions were due to an increase in forward power and gas prices. The reversal of loss positions acquired as part of the Reliant Energy and Green Mountain Energy acquisitions were valued using forward prices on the acquisition dates. The roll-off amounts were offset by realized losses at the settled prices and higher costs of physical power which are reflected in operating costs and expenses during the same period.

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the three months ended March 31, 2012, and 2011. The realized financial and physical trading results are included in operating revenue and the unrealized financial and physical trading results are included in other revenue. The Company's trading activities are subject to limits within the Company's Risk Management Policy.

	Three months ended March 31,
(In millions)	2012			2011
Trading gains/(losses)
Realized	$	11		$	(3	)
Unrealized	(2		)	14
Total trading gains	$	9		$	11

Contract Amortization Revenue

Contract amortization represents the roll-off of in-market customer contracts valued under purchase accounting and the favorable change of $16 million as compared to the prior period in 2011 related primarily to lower contract amortization for Reliant Energy of $12 million and $4 million for Green Mountain Energy.

54

Other Operating Costs

	Retail	Texas	Northeast	South Central	West	Other	Alternative Energy	Corporate	Total
	(In millions)
Three months ended March 31, 2012	$57	$144	$53	$20	$14	$27	$5	$(15)	$305
Three months ended March 31, 2011	$47	$121	$59	$20	$18	$17	$3	$(2)	$283

Other operating costs increased by $22 million for the three months ended March 31, 2012, compared to the same period in 2011, due to:

Increase in Texas region operations and maintenance expense	$	23
Increase in Retail operations and maintenance expense	9
Decrease in Northeast region operations and maintenance expense	(2		)
Decrease in West region operations and maintenance expense	(4		)
Gain on sale of plant assets in current quarter	(4		)
	$	22

◦ Texas operations and maintenance— increased primarily due to outage work in 2012 at coal plants, including Limestone and W.A. Parish, and increased maintenance spending at gas plants including the costs to remove two units from mothball status in preparation for the summer.

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

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

◦ West operations and maintenance expense— decreased due to timing of maintenance work at Encina.

Depreciation and Amortization Expense

Depreciation and amortization expense increased by $25 million for the three months ended March 31, 2012, compared to the same period in 2011. This was primarily due to additional depreciation related to solar facilities which commenced commercial operations in late 2011 and early 2012, as well as the amortization of the intangibles acquired in connection with the acquisition of Energy Plus.

Selling, General and Administrative Expenses

Selling, general and administrative expenses increased by $78 million for the three months ended March 31, 2012, compared to the same period in 2011, which was due primarily to the following:

◦Selling, general and administrative costs of $20 million for Energy Plus which was acquired in September 2011;

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

◦Transaction costs of $8 million associated with the sale of 49% of Agua Caliente;

◦ Increase in marketing costs of $14 million associated with additional marketing costs for the Retail businesses from increased customer counts and marketing efforts as well as new sponsorship agreements; and

◦Increase in labor costs of $5 million for additional solar projects and acquired solar distribution businesses.

Equity in Earnings of Unconsolidated Affiliates

NRG's equity earnings from unconsolidated affiliates were $8 million for the three months ended March 31, 2012, compared to equity losses of $2 million for the same period in 2011 primarily due to an increase in the earnings from Sherbino driven by favorable valuation of hedged positions and an increase in earnings from GenConn as the Middletown facility reached commercial operations in June 2011.

55

Impairment Charge on Investment

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

Loss on Debt Extinguishment

A loss on debt 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 redemption and the write-off of previously deferred financing costs.

Interest Expense

NRG's interest expense decreased by $8 million for the three months ended March 31, 2012, compared to the same period in 2011 due to the following:

Increase/(decrease) in interest expense	(In millions)
Decrease for 2016 Senior Notes redeemed in May and June 2011	$	(44	)
Increase for 2019 and 2021 Senior Notes issued in May 2011	39
Increase for project financings	11
Decrease for 2014 Senior Notes redeemed in January and February 2011	(8		)
Increase for 2018 Senior Notes issued in January 2011	6
Decrease for capitalized interest	(5		)
Decrease for reduction in revolving credit facility	(7		)
Total	$	(8	)

Income Tax Benefit

For the three months ended March 31, 2012, NRG recorded an income tax benefit of $120 million on a pre-tax loss of $326 million. For the same period in 2011, NRG recorded an income tax benefit of $105 million on a pre-tax loss of $365 million. The effective tax rate was 36.8% and 28.8% for the three months ended March 31, 2012, and 2011, respectively.

For the three months ended March 31, 2012, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the generation of ITCs from the Company's Agua Caliente solar project in Arizona.

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.

56

Liquidity and Capital Resources

Liquidity Position

As of March 31, 2012, and December 31, 2011, NRG's liquidity, excluding collateral received, was approximately $2.4 billion and $2.1 billion, respectively, comprised of the following:

(In millions)	March 31, 2012			December 31, 2011
Cash and cash equivalents	$	1,014		$	1,105
Funds deposited by counterparties	199			258
Restricted cash	217			292
Total	1,430			1,655
2011 Revolving Credit Facility availability	1,141			673
Total liquidity	2,571			2,328
Less: Funds deposited as collateral by hedge counterparties	(199		)	(258		)
Total liquidity, excluding collateral received	$	2,372		$	2,070

For the three months ended March 31, 2012, total liquidity, excluding collateral received, increased by $302 million due to higher 2011 Revolving Credit Facility availability, offset by lower cash and cash equivalent and restricted cash balances. The increase in the 2011 Revolving Credit Facility availability was primarily due to a $304 million reduction in letters of credit due to the sale of a 49% interest in Agua Caliente in January 2012 to MidAmerican, and the addition of the NRG Repowering credit facility in January 2012 as discussed in Note 8, Debt and Capital Leases, to this Form 10-Q. Changes in cash and cash equivalent balances are further discussed hereinafter under the heading CashFlow Discussion. Cash and cash equivalents and funds deposited by counterparties at March 31, 2012 were predominantly held in money market funds invested in treasury securities, treasury repurchase agreements or government agency debt.

Included in restricted cash is $121 million of cash and cash equivalents held in controlled accounts as collateral to support the Company's equity funding obligations for the Ivanpah, Agua Caliente, and CVSR projects, as required by the U.S. DOE, which guarantees the Agua Caliente, Ivanpah, and CVSR debt. This collateral can be replaced, at the Company's discretion, with a letter of credit in order to utilize such cash for other purposes. The Company's total liquidity excluding such amounts is $2.3 billion.

The line item "Funds deposited by counterparties" represents the amounts that are held by NRG as a result of collateral posting obligations from the Company's counterparties due to positions in the Company's hedging program. These amounts are segregated into separate accounts that are not contractually restricted but, based on the Company's intention, are not available for the payment of NRG's general corporate obligations. Depending on market fluctuation and the settlement of the underlying contracts, the Company will refund this collateral to the counterparties pursuant to the terms and conditions of the underlying trades. Since collateral requirements fluctuate daily and the Company cannot predict if any collateral will be held for more than 12 months, the funds deposited by counterparties are classified as a current asset on the Company's balance sheet, with an offsetting liability for this cash collateral received within current liabilities.

Management believes that the Company's liquidity position and cash flows from operations will be adequate to finance operating and maintenance capital expenditures, to fund dividends to NRG's preferred stockholders, 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.

57

SOURCES OF LIQUIDITY

The principal sources of liquidity for NRG's future operating and capital expenditures are expected to be derived from new and existing financing arrangements, existing cash on hand and cash flows from operations. As described in Note 8, Debt and Capital Leases, to this Form 10-Q and Note 12, Debt and Capital Leases, to the Company's 2011 Form 10-K, the Company's financing arrangements consist mainly of the 2011 Senior Credit Facility, the Senior Notes, and project-related financings.

In addition, NRG has granted first liens to certain counterparties on substantially all of the Company's assets. NRG uses the first lien structure to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or MWh equivalents. To the extent that the underlying hedge positions for a counterparty are in-the-money to NRG, the counterparty would have no claim under the lien program. The lien program limits the volume that can be hedged, not the value of underlying out-of-the-money positions. The first lien program does not require NRG to post collateral above any threshold amount of exposure. Within the first lien structure, the Company can hedge up to 80% of its baseload capacity and 10% of its non-baseload assets with these counterparties for the first 60 months and then declining thereafter. Net exposure to a counterparty on all trades must be positively correlated to the price of the relevant commodity for the first lien to be available to that counterparty. The first lien structure is not subject to unwind or termination upon a ratings downgrade of a counterparty and has no stated maturity date.

The Company's lien counterparties may have a claim on its assets to the extent market prices exceed the hedged prices. As of March 31, 2012, all hedges under the first liens were in-the-money on a counterparty aggregate basis.

The following table summarizes the amount of MWs hedged against the Company's baseload assets and as a percentage relative to the Company's baseload capacity under the first lien structure as of March 31, 2012:

Equivalent Net Sales Secured by First Lien Structure (a)	2012		2013		2014		2015		2016
In MW (b)	1,864		1,768		1,793		541		635
As a percentage of total net baseload capacity (c)	28	%	26	%	27	%	8	%	10	%

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

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

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

USES OF LIQUIDITY

The Company's requirements for liquidity and capital resources, other than for operating its facilities, can generally be categorized by the following: (i) commercial operations activities; (ii) debt service obligations; (iii) capital expenditures, including repowering and renewable development, and environmental; and (iv) corporate financial transactions including return of capital to stockholders.

Commercial Operations

NRG's commercial operations activities require a significant amount of liquidity and capital resources. These liquidity requirements are primarily driven by: (i) margin and collateral posted with counterparties; (ii) margin and collateral required to participate in physical markets and commodity exchanges; (iii) timing of disbursements and receipts (i.e. buying fuel before receiving energy revenues); (iv) initial collateral for large structured transactions; and (v) collateral for project development. As of March 31, 2012, commercial operations had total cash collateral outstanding of $495 million, and $707 million outstanding in letters of credit to third parties primarily to support its commercial activities for both wholesale and retail transactions (includes a $51 million letter of credit relating to deposits at the PUCT that cover outstanding customer deposits and residential advance payments). As of March 31, 2012, total collateral held from counterparties was $199 million in cash, and $9 million of letters of credit.

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

58

Capital Expenditures

The following tables and descriptions summarize the Company's capital expenditures, including accruals, for maintenance, environmental, and growth investments for the three months ended March 31, 2012, and the estimated capital expenditure and growth investments forecast for the remainder of 2012. 

	Maintenance			Environmental			Growth Investments			Total
	(In millions)
Northeast	$	1		$	9		$	—		$	10
Texas	37			—			—			37
South Central	3			—			—			3
West	2			—			60			62
Other Conventional	2			—			11			13
Retail	4			—			—			4
Solar	—			—			837			837
Total capital expenditures for the the three months ended March 31, 2012	49			9			908			966
Accrual impact	(1		)	12			(338		)	(327		)
Total cash capital expenditures for the three months ended March 31, 2012	48			21			570			639
Other investments (a)	—			—			(75		)	(75		)
Funding from debt financing, net of fees	—			(9		)	(398		)	(407		)
Funding from third party equity partners	—			—			(56		)	(56		)
Total capital expenditures and investments, net	$	48		$	12		$	41		$	101
Estimated capital expenditures for the remainder of 2012	$	211		$	32		$	3,003		$	3,246
Other investments (a)	—			—			(131		)	(131		)
Funding from debt financing, net of fees	—			(32		)	(2,283		)	(2,315		)
Funding from third party equity partners	—			—			(205		)	(205		)
NRG estimated capital expenditures for the remainder of 2012, net of financings	$	211		$	—		$	384		$	595

(a) Other investments include initial investments in projects; network upgrade fees, restricted cash activity and proceeds from cash grants.

• Maintenance and Environmental capital expenditures — For the three months ended March 31, 2012, the Company's environmental capital expenditures included $9 million related to a project to install selective catalytic reduction systems, scrubbers and fabric filters on Indian River Unit 4. The system was operational at year-end 2011 and is undergoing performance testing.

• Growth Investments capital expenditures — For the three months ended March 31, 2012, the Company's growth investment expenditures included $837 million for solar projects and $60 million for the Company's El Segundo project. In 2012, NRG will be continuing its efforts on the solar and El Segundo projects.

59

Environmental Capital Expenditures

Based on current rules, technology and plans, as well as preliminary plans based on proposed rules, NRG has estimated that environmental capital expenditures from 2012 through 2016 to meet NRG's environmental commitments will be approximately $553 million. These costs are primarily associated with mercury controls to satisfy MATS on the Company's Big Cajun II, W.A. Parish and Limestone facilities and a number of intake modification projects across the fleet under state or proposed federal 316(b) rules. NRG continues to explore cost effective compliance alternatives to reduce costs. While this estimate reflects anticipated schedules and controls related to the proposed 316(b) Rule, the full impact on the scope and timing of environmental retrofits from any new or revised regulations cannot be determined until these rules are final and any legal challenges are reviewed. However, NRG believes it is positioned to meet more stringent requirements through its planned capital expenditures, existing controls, and increasing generation from renewable resources.

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

2012 Capital Allocation Program

On February 28, 2012, the Company announced its intention to initiate an annual common stock dividend of $0.36 per share, with the first quarterly payment expected to be paid in the third quarter of 2012.  Furthermore, the Company still intends to refinance its remaining $1.1 billion of 2017 Senior Notes to simplify its capital structure and better align covenant packages, but any refinancing will depend on market conditions and is therefore subject to change. Upon completion of this undertaking, a more flexible 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 stockholders.

As part of the 2012 program, the Company plans to invest approximately $271 million in maintenance and environmental capital expenditures in existing assets, and approximately $425 million in solar and other projects under development.

60

Cash Flow Discussion

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

Three months ended March 31,	2012			2011			Change
	(In millions)
Net cash (used)/provided by operating activities	$	(76	)	$	216		$	(292	)
Net cash used by investing activities	(543		)	(228		)	(315		)
Net cash provided/(used) by financing activities	527			(232		)	759

Net Cash Used By Operating Activities

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

	(In millions)
Decrease in operating income adjusted for non-cash charges	$	(128	)
Change in cash paid in support of risk management activities, including option premium collected/paid,    primarily related to margin posted for retail supply positions	(238		)
Other changes in working capital, which primarily reflects a change in timing of interest payments related to  Senior Notes that were redeemed and issued in 2011	74
	$	(292	)

Net Cash Used By Investing Activities

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

	(In millions)
Increase in capital expenditures due to increased spending on maintenance and RepoweringNRG, primarily for solar projects under construction	$	(420	)
Decrease in restricted cash, which was mainly to support equity requirements for U.S. DOE funded projects	80
Increase in notes receivable	(19		)
Receipt of cash grants	28
Other	16
	$	(315	)

Net Cash Provided By Financing Activities

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

	(In millions)
Net decrease in borrowings of debt, primarily related to the issuance of $1.2 billion under the 2018 Senior Notes in January 2011, compared to $415 million which mainly related to financing arrangements for solar projects in construction	$	(871	)
Cash paid for repurchases of treasury stock in 2011	130
Net decrease in debt payments, primarily from the redemption of the 2014 Senior Notes for $1.2 billion in January 2011	1,328
Proceeds from the sale of noncontrolling interest and other contributions from noncontrolling interests	178
Other	(6		)
	$	759

61

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

For the three months ended March 31, 2012, the Company had a total domestic pre-tax book loss of $336 million and foreign pre-tax book income of $10 million. For the three months ended March 31, 2012, the Company utilized net operating losses, or NOLs, of $13 million. As of March 31, 2012, the Company has cumulative domestic NOL carryforwards of $226 million for financial statement purposes. In addition, NRG has cumulative foreign NOL carryforwards of $259 million, of which $76 million will expire starting 2012 through 2019 and of which $183 million do not have an expiration date.

In addition to these amounts, the Company has $181 million of tax effected uncertain tax benefits. As a result of the Company's tax position, and based on current forecasts, NRG anticipates income tax payments, primarily due to foreign, state and local jurisdictions, of up to $50 million in 2012.

However, as the position remains uncertain for the $181 million of tax effected uncertain tax benefits, the Company has recorded a non-current tax liability of $62 million and may accrue the remaining balance as an increase to non-current liabilities until final resolution with the related taxing authority. The $62 million non-current tax liability for uncertain tax benefits is primarily from positions taken on various state returns, including accrued interest.

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

62

New and On-going Company Initiatives and Development Projects

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

Renewable Development and Acquisitions

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

Solar

NRG has acquired and is developing a number of solar projects utilizing photovoltaic, or PV, as well as solar thermal technologies. The following table is a brief summary of the Company's major Utility Scale Solar projects as of March 31, 2012, that are under construction.

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

(a) Represents total project size.

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

(c) Includes 110 MW, which reached commercial operations from January through April of 2012.

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

Agua Caliente— In 2011, NRG acquired 100% of the 290 MW Agua Caliente solar project, or Agua Caliente, in Yuma, AZ. On January 18, 2012, the Company completed the sale of a 49% interest in NRG Solar AC Holdings LLC, the indirect owner of Agua Caliente, to MidAmerican. Operations are scheduled to commence in phases through the first quarter of 2014, with 110 MW achieving commercial operations from January through April of 2012. On April 12, 2012, the Company received permission from the U.S. DOE to accelerate the block completion schedule. The impact of this decision will permit the Company to bring 245 MW on-line during 2012 and shortens the commercial operations date of the entire project by three months to March 2014. The acceleration will result in greater earnings earlier than originally anticipated, along with acceleration of payments under the Engineering, Procurement and Construction, or EPC, agreement which will be funded with earlier draw downs under the Agua Caliente Financing Agreement, as well as equity support by the partners. Power generated from Agua Caliente will be sold to Pacific Gas and Electric under a 25 year PPA.

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

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

63

Distributed Solar

NRG's installation of solar power generating systems at MetLife Stadium, Gillette Stadium and Patriot Place is continuing, with construction at MetLife and Gillette Stadium anticipated being complete by the end of the third quarter of 2012. Additionally, in February 2012, NRG announced that it will install a solar power generating system at Lincoln Financial Field, home of the Philadelphia Eagles, which is anticipated to be completed by the end of 2012. All of the Company's Distributed Solar projects in operation or under construction are supported by long-term PPAs.

Conventional Power Development

Projects Under Construction

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

Retail Growth Initiatives

The Company's Retail businesses are expanding in the Northeast through a combination of new sales channels, partner marketing programs, and new product offerings. NRG grew its Northeast customer base by 10% during the first quarter of 2012, and the Retail businesses are currently operating in 12 states.

Also, the Company continues to grow its renewable customer base. At the end of the first quarter of 2012, about 300,000 of its retail electricity customers were on a 100% “green” electric product. Plus, Green Mountain Energy gained an iconic commercial customer by being selected as the official green energy provider of Super Bowl XLVI and this year's Pro Bowl, with the Company offsetting the carbon emissions from each event.

NRG also continues to expand its Reliant eSense^TM product offerings. eSense is a suite of technology solutions that uses the advanced meter system network (smart meters) that is being rolled out to customers in ERCOT.  Through March 31, 2012, Reliant had 600,000 customers using one of these products that provide customers with energy insights, choices and convenience solutions.

Reliant also continues to expand its Home Solutions^SM business with 250,000 customers utilizing home services products including protection products such as surge protection, in home power line protection, HVAC maintenance and energy efficiency products like air filter delivery and solar panel leasing.

Electric Vehicle Infrastructure Development

NRG, through its subsidiary eVgo, continues its build out of the Houston and Dallas/Fort Worth Metroplex, or DFW, EV ecosystems, and the Company is on track to be the first company to equip an entire major market with the privately funded infrastructure needed for successful EV adoption and integration. As of March 31, 2012, eVgo had 17 public fast charging Freedom Station sites operational, under construction, or in permitting in Houston, and 16 in DFW. These two ecosystems are the largest metropolitan-area networks of DC fast chargers in the nation. eVgo offers consumers a subscription-based plan that locks in all charging requirements for EVs at a competitive monthly fee. Based upon the successful launch of its subscription-based business model in Texas, eVgo is poised to enter the Washington, DC/Baltimore market.

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

Post-combustion Carbon Capture Project

NRG, through its wholly owned subsidiary Petra Nova LLC, is continuing development of an up-to 240 MW-equivalent Post-Combustion Carbon Capture commercial scale unit at NRG's W.A. Parish plant, with the intent of using the captured CO₂ in enhanced oil recovery operations in oil fields on the Texas Gulf Coast. NRG is currently progressing through a Pipeline front-end engineering and design study and the Environmental Impact Statement process, the latter required under the National Environmental Policy Act.

64

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, 2012, based on the Company's stock price, the embedded derivative was out-of-the-money and had no redemption value.

Obligations Arising Out of a Variable Interest in an Unconsolidated Entity

Variable interest in equity investments — As of March 31, 2012, NRG has several investments with an ownership interest percentage of 50% or less in energy and energy-related entities that are accounted for under the equity method of accounting. Several of these investments are variable interest entities for which NRG is not the primary beneficiary. See also Note 9, Variable Interest Entities, or VIEs, to this Form 10-Q.

NRG's pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $243 million as of March 31, 2012. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG. See also Note 16, Investments Accounted for by the Equity Method and Variable Interest Entities, to the Company's 2011 Form 10-K.

Contractual Obligations and Commercial Commitments

NRG has a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to the Company's capital expenditure programs, as disclosed in the Company's 2011 Form 10-K. See also Note 8, Debt and Capital Leases, and Note 14, Commitments and Contingencies, to this Form 10-Q for a discussion of new commitments and contingencies that also include contractual obligations and commercial commitments that occurred during the three months ended March 31, 2012.

65

Fair Value of Derivative Instruments

NRG may enter into long-term power purchase and sales contracts, fuel purchase contracts and other energy-related financial instruments to mitigate variability in earnings due to fluctuations in spot market prices and to hedge fuel requirements at generation facilities or retail load obligations. In addition, in order to mitigate interest rate risk associated with the issuance of the Company's variable rate and fixed rate debt, NRG enters into interest rate swap agreements. The following disclosures about fair value of derivative instruments provide an update to, and should be read in conjunction with, Fair Value of Derivative Instruments in Item 7 — Management's Discussion and Analysis of Financial Condition and Results of Operations, of the Company's 2011 Form 10‑K.

The tables below disclose the activities that include both exchange and non-exchange traded contracts accounted for at fair value in accordance with ASC 820, Fair Value Measurements and Disclosures, or ASC 820. Specifically, these tables disaggregate realized and unrealized changes in fair value; disaggregate estimated fair values at March 31, 2012, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at March 31, 2012.

Derivative Activity Gains/(Losses)	(In millions)
Fair value of contracts as of December 31, 2011	$	451
Contracts realized or otherwise settled during the period	(68		)
Changes in fair value	(116		)
Fair value of contracts as of March 31, 2012	$	267

	Fair Value of Contracts as of March 31, 2012
Fair value hierarchy gains/(losses)	Maturity Less Than 1 Year			Maturity 1-3 Years			Maturity 4-5 Years			Maturity in Excess 4-5 Years		Total Fair Value
	(In millions)
Level 1	$	(36	)	$	(47	)	$	(9	)	$	—	$	(92	)
Level 2	328			77			(95		)	6		316
Level 3	34			9			—			—		43
Total	$	326		$	39		$	(104	)	$	6	$	267

The Company has elected to disclose derivative assets and liabilities on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. Also, collateral received or paid on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. Consequently, the magnitude of the changes in individual current and non-current derivative assets or liabilities is higher than the underlying credit and market risk of the Company's portfolio. As discussed in Item 3 - Quantitative and Qualitative Disclosures About Market Risk, Commodity Price Risk, to this Form 10-Q, NRG measures the sensitivity of the Company's portfolio to potential changes in market prices using Value at Risk, or VaR, a statistical model which attempts to predict risk of loss based on market price and volatility. NRG's risk management policy places a limit on one-day holding period VaR, which limits the Company's net open position. As the Company's trade-by-trade derivative accounting results in a gross-up of the Company's derivative assets and liabilities, the net derivative assets and liability position is a better indicator of NRG's hedging activity. As of March 31, 2012, NRG's net derivative asset was $267 million, a decrease to total fair value of $184 million as compared to December 31, 2011. This decrease was primarily driven by the roll-off of trades that settled during the period in addition to losses in fair value due to the decreases in coal, gas and power prices and increases in ERCOT heat rates.

Based on a sensitivity analysis using simplified assumptions, 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 $245 million in the net value of derivatives as of March 31, 2012.

66

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, legal and regulatory challenges, and the fair value of certain assets and liabilities. These judgments, in and of themselves, could materially affect the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment may also have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies 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 information that gives rise to the revision becomes known.

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

67

ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

NRG is exposed to several market risks in the Company's normal business activities. Market risk is the potential loss that may result from market changes associated with the Company's merchant power generation or with an existing or forecasted financial or commodity transaction. The types of market risks the Company is exposed to are commodity price risk, interest rate risk, liquidity risk, credit risk and currency exchange risk. The following disclosures about market risk provide an update to, and should be read in conjunction with, Item 7A —Quantitative and Qualitative Disclosures About Market Risk, of the Company's 2011 Form 10-K.

Commodity Price Risk

Commodity price risks result from exposures to changes in spot prices, forward prices, volatilities, and correlations between various commodities, such as natural gas, electricity, coal, oil, and emissions credits. NRG manages the commodity price risk of the Company's merchant generation operations and load serving obligations by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted sales and purchases of electricity and fuel. NRG measures the risk of the Company's portfolio using several analytical methods, including sensitivity tests, scenario tests, stress tests, position reports, and Value at Risk, or VaR. NRG uses a Monte Carlo simulation based VaR model to estimate the potential loss in the fair value of the Company's energy assets and liabilities, which includes generation assets, load obligations, and bilateral physical and financial transactions.

As of March 31, 2012, the VaR for NRG's commodity portfolio, including generation assets, load obligations and bilateral physical and financial transactions calculated using the VaR model was $51 million.

The following table summarizes average, maximum and minimum VaR for NRG for the three months ended March 31, 2012, and 2011:

(In millions)	2012		2011
VaR as of March 31	$	51	$	52
Three months ended March 31:
Average	$	34	$	51
Maximum	53		56
Minimum	24		44

In order to provide additional information for comparative purposes to NRG's peers, the Company also uses VaR to estimate the potential loss of derivative financial instruments that are subject to mark-to-market accounting. These derivative instruments include transactions that were entered into for both asset management and trading purposes. The VaR for the derivative financial instruments calculated using the diversified VaR model as of March 31, 2012, for the entire term of these instruments entered into for both asset management and trading, was $22 million primarily driven by asset-backed transactions.

Interest Rate Risk

NRG is exposed to fluctuations in interest rates through the Company's issuance of fixed rate and variable rate debt. Exposures to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combination of the variable rate debt and the interest rate derivative instrument. NRG's risk management policies allow the Company to reduce interest rate exposure from variable rate debt obligations.

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

68

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

If all of the above swaps had been discontinued on March 31, 2012, the Company would have owed the counterparties $91 million. Based on the investment grade rating of the counterparties, NRG believes its exposure to credit risk due to nonperformance by counterparties to its hedge contracts to be insignificant.

As part of the CVSR financing, the Company entered into swaptions with a notional value of $686 million in order to hedge the project interest rate risk. If the swaptions were discontinued on March 31, 2012, the counterparty would have owed the Company approximately $33 million.

NRG has both long and short-term debt instruments that subject the Company to the risk of loss associated with movements in market interest rates. As of March 31, 2012, a 1% change in interest rates would result in an $8 million change in interest expense on a rolling twelve month basis.

As of March 31, 2012, the fair value of the Company's debt was approximately equal to its carrying value of $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 by $811 million.

Liquidity Risk

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

Based on a sensitivity analysis for power and gas positions under marginable contracts, a $1 per MMBtu change in natural gas prices across the term of the marginable contracts would cause a change in margin collateral posted of approximately $262 million as of March 31, 2012, and a 1 MMBtu/MWh change in heat rates for heat rate positions would result in a change in margin collateral posted of approximately $48 million as of March 31, 2012. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of March 31, 2012.

Credit Risk

Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. NRG is exposed to counterparty credit risk through various activities including wholesale sales, fuel purchases and retail supply arrangements, and retail customer credit risk through its retail load activities. See Note 5, Fair Value of Financial Instruments, to this Form 10-Q for discussions regarding counterparty credit risk and retail customer credit risk, and Note 7, Accounting for Derivative Instruments and Hedging Activities, to this Form 10-Q for discussion regarding credit risk contingent features.

Currency Exchange Risk

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.

69

ITEM 4 — CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure ControlsandProcedures

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

Changes in Internal Control over Financial Reporting

There were no changes in the Company's internal controls over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred in the first quarter of 2012 that materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

70

PART II — OTHER INFORMATION

ITEM 1 — LEGAL PROCEEDINGS

For a discussion of material legal proceedings in which NRG was involved through March 31, 2012, see Note 14, Commitments and Contingencies, to this Form 10-Q.

ITEM 1A — RISK FACTORS

Information regarding risk factors appears in Part I, Item 1A, RiskFactors Related to NRG Energy, Inc., in the Company's 2011 Form 10-K.

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

None.

ITEM 3 — DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4 — MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5 — OTHER INFORMATION

None.

71

ITEM 6 — EXHIBITS

Exhibits
3.1	Amended and Restated Certificate of Incorporation of NRG Energy, Inc.
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

72

SIGNATURES

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

	NRG ENERGY, INC. (Registrant)
	/s/ DAVID W. CRANE
	David W. Crane
	Chief Executive Officer (Principal Executive Officer)
	/s/ KIRKLAND B. ANDREWS
	Kirkland B. Andrews
	Chief Financial Officer (Principal Financial Officer)
	/s/ RONALD B. STARK
	Ronald B. Stark
Date: May 3, 2012	Chief Accounting Officer (Principal Accounting Officer)

73

EXHIBIT INDEX

Exhibits
3.1	Amended and Restated Certificate of Incorporation of NRG Energy, Inc.
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

74