10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended: March 31, 2010

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

Commission File Number: 001-15891

NRG Energy, Inc.

(Exact name of registrant as specified in its charter)

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

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

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

Yes þ No o

     Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

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

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

Yes o No þ

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

Yes þ No o

     As of May 5, 2010, there were 255,312,628 shares of common stock outstanding, par value $0.01 per share.

TABLE OF CONTENTS
Index

CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION	3
GLOSSARY OF TERMS	4
PART I — FINANCIAL INFORMATION	8
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES	8
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	44
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	77
ITEM 4 — CONTROLS AND PROCEDURES	82
PART II — OTHER INFORMATION	83
ITEM 1 — LEGAL PROCEEDINGS	83
ITEM 1A — RISK FACTORS	83
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	83
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES	83
ITEM 4 — (REMOVED AND RESERVED)	83
ITEM 5 — OTHER INFORMATION	83
ITEM 6 — EXHIBITS	84
SIGNATURES	85
EX-31.1
EX-31.2
EX-31.3
EX-32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT

2

CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION

     This Quarterly Report on Form 10-Q of NRG Energy, Inc., or NRG or the Company, includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. The words “believes,” “projects,” “anticipates,” “plans,” “expects,” “intends,” “estimates” and similar expressions are intended to identify forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors which may cause NRG’s actual results, performance and achievements, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. These factors, risks and uncertainties include the factors described under Risks Factors Related to NRG Energy, Inc. in Part I, Item 1A, of the Company’s Annual Report on Form 10-K, for the year ended December 31, 2009, including the following:

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

• Volatile power supply costs and demand for power;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

• Reliant Energy’s ability to maintain market share;

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

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

     Forward-looking statements speak only as of the date they were made, and NRG undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors that could cause NRG’s actual results to differ materially from those contemplated in any forward-looking statements included in this Quarterly Report on Form 10-Q should not be construed as exhaustive.

3

GLOSSARY OF TERMS

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

Baseload capacity	Electric power generation capacity normally expected to serve loads on an around-the-clock basis throughout the calendar year
BACT	Best Available Control Technology
BTU	British Thermal Unit
CAA	Clean Air Act
CAGR	Compound annual growth rate
CAIR	Clean Air Interstate Rule
CAISO	California Independent System Operator
Capital Allocation Plan	Share repurchase program
Capital Allocation Program	NRG’s plan of allocating capital between debt reduction, reinvestment in the business, and share repurchases through the Capital Allocation Plan
CDWR	California Department of Water Resources
C&I	Commercial, industrial and governmental/institutional
CO2	Carbon dioxide
CPS	CPS Energy
CSF Debt	CSF I and CSF II issued notes and preferred interest, individually referred to as CSF I Debt and CSF II Debt
CSRA	Credit Sleeve Reimbursement Agreement with Merrill Lynch in connection with acquisition of Reliant Energy, as hereinafter defined
CSRA Amendment	Amendment of the existing CSRA with Merrill Lynch which became effective October 5, 2009
DNREC	Delaware Department of Natural Resources and Environmental Control
DPUC	Department of Public Utility Control
ERCOT	Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas
Exchange Act	The Securities Exchange Act of 1934, as amended
Expected Baseload Generation	The net baseload generation limited by economic factors (relationship between cost of generation and market price) and reliability factors (scheduled and unplanned outages)
FASB	Financial Accounting Standards Board — the designated organization for establishing standards for financial accounting and reporting
FERC	Federal Energy Regulatory Commission
GHG	Greenhouse Gases
GWh	Gigawatt hour
IGCC	Integrated Gasification Combined Cycle

4

ISO	Independent System Operator, also referred to as Regional Transmission Organizations, or RTO
ISO-NE	ISO New England Inc.
kV	Kilovolts
kW	Kilowatts
kWh	Kilowatt-hours
LIBOR	London Inter-Bank Offer Rate
LTIP	Long-Term Incentive Plan
MACT	Maximum Achievable Control Technology
Mass	Residential and small business
Merit Order	A term used for the ranking of power stations in order of ascending marginal cost
MIBRAG	Mitteldeutsche Braunkohlengesellschaft mbH
MMBtu	Million British Thermal Units
MVA	Megavolt-ampere
MW	Megawatts
MWh	Saleable megawatt hours net of internal/parasitic load megawatt-hours
NAAQS	National Ambient Air Quality Standards
NINA	Nuclear Innovation North America LLC
NOx	Nitrogen oxide
NPNS	Normal Purchase Normal Sale
NRC	U.S. Nuclear Regulatory Commission
NSR	New Source Review
NYISO	New York Independent System Operator
OCI	Other comprehensive income
Phase II 316(b) Rule	A section of the Clean Water Act regulating cooling water intake structures
PJM	PJM Interconnection, LLC
PJM market	The wholesale and retail electric market operated by PJM primarily in all or parts of Delaware, the District of Columbia, Illinois, Maryland, New Jersey, Ohio, Pennsylvania, Virginia and West Virginia
PML	NRG Power Marketing, LLC, a wholly-owned subsidiary of NRG which procures transportation and fuel for the Company’s generation facilities, sells the power from these facilities and supply for Reliant Energy, and manages all commodity trading and hedging for NRG
PPA	Power Purchase Agreement
PUCT	Public Utility Commission of Texas
Reliant Energy	NRG’s retail business in Texas purchased on May 1, 2009, from Reliant Energy, Inc. which is now known as RRI Energy, Inc., or RRI

5

Repowering	Technologies utilized to replace, rebuild, or redevelop major portions of an existing electrical generating facility, not only to achieve a substantial emissions reduction, but also to increase facility capacity, and improve system efficiency
RepoweringNRG	NRG’s program designed to develop, finance, construct and operate new, highly efficient, environmentally responsible capacity
REPS	Reliant Energy Power Supply, LLC
RERH	RERH Holding, LLC and its subsidiaries
Revolving Credit Facility	NRG’s $1 billion senior secured credit facility which matures on February 2, 2011
RGGI	Regional Greenhouse Gas Initiative
RMR	Reliability Must-Run
ROIC	Return on invested capital
RRI	RRI Energy, Inc. (formerly Reliant Energy, Inc.)
Sarbanes-Oxley	Sarbanes-Oxley Act of 2002, as amended
SEC	United States Securities and Exchange Commission
Securities Act	The Securities Act of 1933, as amended
Senior Credit Facility	NRG’s senior secured facility, which is comprised of a Term Loan Facility and a $1.3 billion Synthetic Letter of Credit Facility which matures on February 1, 2013, and a $1 billion Revolving Credit Facility, which matures on February 2, 2011
Senior Notes	The Company’s $5.4 billion outstanding unsecured senior notes consisting of $1.2 billion of 7.25% senior notes due 2014, $2.4 billion of 7.375% senior notes due 2016 and $1.1 billion of 7.375% senior notes due 2017 and $700 million of 8.5% senior notes due 2019
SO2	Sulfur dioxide
STP	South Texas Project — nuclear generating facility located near Bay City, Texas in which NRG owns a 44% Interest
STPNOC	South Texas Project Nuclear Operating Company
Synthetic Letter of Credit Facility	NRG’s $1.3 billion senior secured synthetic letter of credit facility which matures on February 1, 2013
TANE	Toshiba American Nuclear Operating Company
TANE Facility	NINA’s $500 million credit facility with TANE which matures on February 24, 2012
TEPCO	The Tokyo Electric Power Company of Japan, Inc.
Term Loan Facility	A senior first priority secured term loan which matures on February 1, 2013, and is included as part of NRG’s Senior Credit Facility
TNEA	TEPCO Nuclear Energy America LLC
Tonnes	Metric tonnes, which are units of mass or weight in the metric system each equal to 2,205lbs and are the global measurement for GHG
TWh	Terawatt hour
U.S.	United States of America
U.S. DOE	United States Department of Energy
U.S. EPA	United States Environmental Protection Agency
U.S. GAAP	Accounting principles generally accepted in the United States
VaR	Value at Risk

6

ACCOUNTING PRONOUNCEMENTS

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

ASC 280	ASC-280, Segment Reporting
ASC 450	ASC-450, Contingencies
ASC 740	ASC-740, Income Taxes
ASC 805	ASC-805, Business Combinations
ASC 810	ASC-810, Consolidation
ASC 815	ASC-815, Derivatives and Hedging
ASC 820	ASC-820, Fair Value Measurements and Disclosures
ASC 980	ASC-980, Regulated Operations
ASU 2009-15	ASU No. 2009-15, Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing
ASU 2009-17	ASU No. 2009-17, Consolidations: Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities
ASU 2010-02	ASU No. 2010-02, Consolidation (Topic 810): Accounting and Reporting for Decreases in Ownership of a Subsidiary—a Scope Clarification
ASU 2010-06	ASU No. 2010-06, Fair Value Measurement and Disclosures: Improving Disclosures about Fair Value Measurements
ASU 2010-09	ASU No. 2010-09, Subsequent Events (Topic 815): Amendments to Certain Recognition and Disclosure Requirements
ASU 2010-10	ASU No. 2010-10, Consolidation (Topic 810): Amendments for Certain Investment Funds

7

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)	2010			2009
Operating Revenues
Total operating revenues	$	2,215		$	1,658
Operating Costs and Expenses
Cost of operations		1,639			766
Depreciation and amortization		202			169
Selling, general and administrative		130			95
Development costs		9			13
Total operating costs and expenses		1,980			1,043
Gain on sale of assets		23			—
Operating Income		258			615
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates		14			22
Other income/(loss), net		4			(3	)
Interest expense		(153	)		(138	)
Total other expense		(135	)		(119	)
Income Before Income Taxes		123			496
Income tax expense		65			298
Net Income attributable to NRG Energy, Inc.		58			198
Dividends for preferred shares		2			14
Income Available for NRG Energy, Inc. Common Stockholders	$	56		$	184
Earnings per share attributable to NRG Energy, Inc. Common Stockholders
Weighted average number of common shares outstanding — basic		254			237
Net Income per Weighted Average Common Share — basic	$	0.22		$	0.78
Weighted average number of common shares outstanding — diluted		257			275
Net Income per Weighted Average Common Share — diluted	$	0.22		$	0.70

See notes to condensed consolidated financial statements.

8

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS

	March 31, 2010			December 31, 2009
(In millions, except shares)	(unaudited)
ASSETS
Current Assets
Cash and cash equivalents	$	1,813		$	2,304
Funds deposited by counterparties		509			177
Restricted cash		7			2
Accounts receivable — trade, less allowance for doubtful accounts of $21 and $29, respectively		700			876
Inventory		549			541
Derivative instruments valuation		2,724			1,636
Cash collateral paid in support of energy risk management activities		533			361
Prepayments and other current assets		307			311
Total current assets		7,142			6,208
Property, plant and equipment, net of accumulated depreciation of $3,236 and $3,052, respectively		11,627			11,564
Other Assets
Equity investments in affiliates		421			409
Note receivable — affiliate and capital leases, less current portion		476			504
Goodwill		1,713			1,718
Intangible assets, net of accumulated amortization of $758 and $648, respectively		1,686			1,777
Nuclear decommissioning trust fund		382			367
Derivative instruments valuation		975			683
Other non-current assets		156			148
Total other assets		5,809			5,606
Total Assets	$	24,578		$	23,378
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	152		$	571
Accounts payable		595			697
Derivative instruments valuation		2,354			1,473
Deferred income taxes		174			197
Cash collateral received in support of energy risk management activities		509			177
Accrued expenses and other current liabilities		588			647
Total current liabilities		4,372			3,762
Other Liabilities
Long-term debt and capital leases		7,846			7,847
Nuclear decommissioning reserve		304			300
Nuclear decommissioning trust liability		262			255
Deferred income taxes		1,925			1,783
Derivative instruments valuation		439			387
Out-of-market contracts		277			294
Other non-current liabilities		885			806
Total non-current liabilities		11,938			11,672
Total Liabilities		16,310			15,434
3.625% convertible perpetual preferred stock (at liquidation value, net of issuance costs)		247			247
Commitments and Contingencies
Stockholders’ Equity
Preferred stock (at liquidation value, net of issuance costs)		—			149
Common stock		3			3
Additional paid-in capital		5,274			4,948
Retained earnings		3,388			3,332
Less treasury stock, at cost — 48,411,606 and 41,866,451 shares, respectively		(1,323	)		(1,163	)
Accumulated other comprehensive income		667			416
Noncontrolling interest		12			12
Total Stockholders’ Equity		8,021			7,697
Total Liabilities and Stockholders’ Equity	$	24,578		$	23,378

See notes to condensed consolidated financial statements.

9

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

(In millions)
Three months ended March 31,	2010			2009
Cash Flows from Operating Activities
Net income	$	58		$	198
Adjustments to reconcile net income to net cash provided by operating activities:
Distributions and equity in earnings of unconsolidated affiliates		(5	)		(22	)
Depreciation and amortization		202			169
Provision for bad debts		9			—
Amortization of nuclear fuel		10			10
Amortization of financing costs and debt discount/premiums		8			9
Amortization of intangibles and out-of-market contracts		—			(34	)
Changes in deferred income taxes and liability for unrecognized tax benefits		74			299
Changes in nuclear decommissioning trust liability		11			6
Changes in derivatives		24			(304	)
Changes in collateral deposits supporting energy risk management activities		(172	)		312
Gain on sale of assets		(21	)		(1	)
Gain on sale of emission allowances		—			(7	)
Amortization of unearned equity compensation		6			7
Changes in option premiums collected		92			(270	)
Cash used by changes in other working capital		(182	)		(233	)
Net Cash Provided by Operating Activities		114			139
Cash Flows from Investing Activities
Capital expenditures		(185	)		(233	)
Increase in restricted cash, net		(5	)		(1	)
Decrease in notes receivable		7			3
Purchases of emission allowances		(34	)		(35	)
Proceeds from sale of emission allowances		9			8
Investments in nuclear decommissioning trust fund securities		(78	)		(83	)
Proceeds from sales of nuclear decommissioning trust fund securities		67			78
Proceeds from sale of assets		30			4
Other		(5	)		—
Net Cash Used by Investing Activities		(194	)		(259	)
Cash Flows from Financing Activities
Payment of dividends to preferred stockholders		(2	)		(14	)
Net receipts from acquired derivatives that include financing elements		13			40
Proceeds from issuance of long-term debt		10			—
Proceeds from issuance of common stock		2			—
Payment of deferred debt issuance costs		(2	)		(1	)
Payments for short and long-term debt		(429	)		(209	)
Net Cash Used by Financing Activities		(408	)		(184	)
Effect of exchange rate changes on cash and cash equivalents		(3	)		(2	)
Net Decrease in Cash and Cash Equivalents		(491	)		(306	)
Cash and Cash Equivalents at Beginning of Period		2,304			1,494
Cash and Cash Equivalents at End of Period	$	1,813		$	1,188

See 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 primarily a wholesale power generation company with a significant presence in major competitive power markets in the United States of America, or U.S., as well as a major retail electricity provider in the ERCOT (Texas) market. NRG is engaged in the ownership, development, construction and operation of power generation facilities, both conventional and renewable, the transacting in and trading of fuel and transportation services, the trading of energy, capacity and related products in the U.S. and select international markets, and supply of electricity and energy services to retail electricity customers in the Texas market. The Company also seeks to invest in and deploy new energy technologies.

     The accompanying unaudited interim condensed consolidated financial statements have been prepared in accordance with the U.S. 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, 2009. 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, 2010, and the results of operations and cash flows for the three months ended March 31, 2010, and 2009.

  Use of Estimates

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

Note 2 — Summary of Significant Accounting Policies

  Other Cash Flow Information

     NRG’s investing activities do not include non-cash capital expenditures of $90 million which were accrued at March 31, 2010.

  Recent Accounting Developments

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

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

11

     Other effects of ASU 2009-17/ASU 2010-10 adoption — NRG determined that one of its equity method investments was a VIE as of January 1, 2010, upon adoption of this new guidance. NRG owns a 50% interest in Sherbino I Wind Farm LLC, or Sherbino, a 150MW wind farm operated as a joint venture with BP Wind Energy North America Inc., or BP Wind. The Company has determined that Sherbino is a VIE, but the Company is not the primary beneficiary, under the amended guidance in ASU 2009-17 and ASU 2010-10. Therefore, NRG will continue to account for its investment in Sherbino under the equity method. NRG’s maximum exposure to loss is limited to its equity investment, which is $101 million as of March 31, 2010.

     Borrowings of an equity method investment — In December 2008 Sherbino entered into a 15-year term loan facility which is non-recourse to NRG. As of March 31, 2010 the outstanding principal balance of the term loan facility was $133 million, and is secured by substantially all of Sherbino’s assets and membership interests.

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

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

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

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

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

Note 3 — Comprehensive Income

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

(In millions)
Three months ended March 31,	2010			2009
Net Income attributable to NRG Energy, Inc.	$	58		$	198
Changes in derivative activity		257			173
Foreign currency translation adjustment		(6	)		(18	)
Unrealized gain on available-for-sale securities		—			1
Other comprehensive income	$	251			156
Comprehensive income	$	309		$	354

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

(In millions)
Accumulated other comprehensive income as of December 31, 2009	$	416
Changes in derivative activity		257
Foreign currency translation adjustment		(6	)
Accumulated other comprehensive income as of March 31, 2010	$	667

12

Note 4 —Acquisitions and Dispositions

  Acquisition of Reliant Energy

     On May 1, 2009, NRG, through its wholly-owned subsidiary NRG Retail LLC, acquired Reliant Energy from RRI Energy, Inc., or RRI, which consisted of the entire Texas electric retail business operations of RRI, including the exclusive use of the trade name “Reliant” and related branding rights. The acquisition of Reliant Energy was accounted for under the acquisition method of accounting in accordance with ASC 805. Accordingly, NRG conducted an assessment of net assets acquired and recognized identifiable assets acquired and liabilities assumed at their acquisition date fair values. The accounting for this business combination was complete as of March 31, 2010.

     NRG paid RRI $287.5 million in cash at closing, and made payments to RRI of $79 million as remittances of acquired net working capital. In addition, the Company expects to remit approximately $3 million of acquired net working capital to RRI by the second quarter 2010, bringing the total cash consideration to approximately $370 million. NRG also recognized a $31 million non-cash gain at the acquisition date, on the settlement of a pre-existing relationship, representing the in-the-money value to NRG of an agreement that permits Reliant Energy to call on certain NRG gas plants when necessary for Reliant Energy to meet its load obligations. This non-cash gain was considered a component of consideration in accordance with ASC 805, and together with cash consideration, brings total consideration to approximately $401 million.

     The following table summarizes the values assigned to the net assets acquired, including cash acquired of $6 million, as of the acquisition date:

	(In millions)
Assets
Current and non-current assets	$	635
Property, plant and equipment		72
Intangible assets subject to amortization:
In-market customer contracts		790
Customer relationships		405
Trade names		178
In-market energy supply contracts		54
Other		6
Derivative assets		1,942
Deferred tax asset, net		14
Goodwill		—
Total assets acquired	$	4,096
Liabilities
Current and non-current liabilities	$	556
Derivative liabilities		2,996
Out-of-market energy supply and customer contracts		143
Total liabilities assumed	$	3,695
Net assets acquired	$	401

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Measurement period adjustments

     The following measurement period adjustments to the provisional amounts, attributable to refinement of the underlying appraisal assumptions, were recognized during 2009 subsequent to the acquisition date and the first quarter of 2010:

	Increase/(Decrease)
	(In millions)
Assets
Intangible assets subject to amortization:
In-market customer contracts	$	57
Customer relationships		(76	)
In-market energy supply contracts		17
Deferred tax asset, net		3
Total assets acquired		1
Liabilities
Current and non-current liabilities		6
Out-of-market energy supply and customer contracts		(5	)
Total liabilities assumed		1
Net assets acquired	$	—

  Disposition of Padoma

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

Note 5 — Fair Value of Financial Instruments

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

	Carrying Amount				Fair Value
	March 31,		December 31,		March 31,		December 31,
	2010		2009		2010		2009
			(In millions)
Cash and cash equivalents	$	1,813	$	2,304	$	1,813	$	2,304
Funds deposited by counterparties		509		177		509		177
Restricted cash		7		2		7		2
Cash collateral paid in support of energy risk management activities		533		361		533		361
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities		9		9		9		9
Marketable equity securities		5		5		5		5
Trust fund investments		384		369		384		369
Notes receivable		229		231		236		238
Derivative assets		3,699		2,319		3,699		2,319
Long-term debt, including current portion		7,883		8,295		7,832		8,211
Cash collateral received in support of energy risk management activities		509		177		509		177
Derivative liabilities	$	2,793	$	1,860	$	2,793	$	1,860

14

  Recurring Fair Value Measurements

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

(In millions)			Fair Value
As of March 31, 2010	Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	1,813	$	—	$	—	$	1,813
Funds deposited by counterparties		509		—		—		509
Restricted cash		7		—		—		7
Cash collateral paid in support of energy risk management activities		533		—		—		533
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities		—		—		9		9
Marketable equity securities		5		—		—		5
Trust fund investments
Cash and cash equivalents		8		—		—		8
U.S. government and federal agency obligations		23		—		—		23
Federal agency mortgage-backed securities		—		63		—		63
Commercial mortgage-backed securities		—		9		—		9
Corporate debt securities		—		48		—		48
Marketable equity securities		194		—		37		231
Foreign government fixed income securities		—		2		—		2
Derivative assets
Commodity contracts		995		2,593		100		3,688
Interest rate contracts		—		—		11		11
Total assets	$	4,087	$	2,715	$	157	$	6,959
Cash collateral received in support of energy risk management activities	$	509	$	—	$	—	$	509
Derivative liabilities
Commodity contracts		1,119		1,430		136		2,685
Interest rate contracts		—		108		—		108
Total liabilities	$	1,628	$	1,538	$	136	$	3,302

(In millions)	Fair Value
As of December 31, 2009	Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	2,304	$	—	$	—	$	2,304
Funds deposited by counterparties		177		—		—		177
Restricted cash		2		—		—		2
Cash collateral paid in support of energy risk management activities		361		—		—		361
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities		—		—		9		9
Marketable equity securities		5		—		—		5
Trust fund investments		214		118		37		369
Derivative assets		489		1,767		63		2,319
Total assets	$	3,552	$	1,885	$	109	$	5,546
Cash collateral received in support of energy risk management activities	$	177	$	—	$	—	$	177
Derivative liabilities		501		1,283		76		1,860
Total liabilities	$	678	$	1,283	$	76	$	2,037

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     There have been no transfers during the three months ended March 31, 2010, between Levels 1 and 2. The following table reconciles the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements using significant unobservable inputs:

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

	Fair Value Measurement Using Significant Unobservable Inputs
	(Level 3)
(In millions)			Trust Fund
Three months ended March 31, 2009	Debt Securities		Investments			Derivatives(a)		Total
Beginning balance as of January 1, 2009	$	7	$	31		$	49	$	87
Total gains/(losses) (realized and unrealized)
Included in earnings		—		—			19		19
Included in nuclear decommissioning trust liability		—		(4	)		—		(4	)
Purchases/(sales), net		—		—			4		4
Transfers in/out of Level 3(b)		—		—			54		54
Ending balance as of March 31, 2009	$	7	$	27		$	126	$	160
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, 2009	$	—	$	—		$	29	$	29

(a)	Consists of derivative assets and liabilities, net
(b)	Transfers in/out of Level 3 are related to the availability of external broker quotes, and are all with Level 2.

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

     In determining the fair value of NRG’s Level 2 and 3 derivative contracts, NRG applies a credit reserve to reflect credit risk which is calculated based on credit default swaps. As of March 31, 2010, the credit reserve resulted in a $2 million decrease in fair value which is composed of a $3 million loss in other comprehensive income, or OCI, and a $1 million gain 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 financial statements in its Annual Report on Form 10-K for the year ended December 31, 2009, the following item is a discussion of the concentration of credit risk for the Company’s financial instruments. Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. NRG is exposed to counterparty credit risk through various activities including wholesale sales, fuel purchases and retail supply and retail customer credit risk through its retail load activities.

16

     Counterparty Credit Risk

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

     As of March 31, 2010, total counterparty credit exposure to substantially all counterparties was $1.7 billion and NRG held cash collateral against those positions of $509 million resulting in a net exposure of $1.2 billion. Total counterparty credit exposure is discounted at the risk free rate.

     The following table highlights the counterparty credit quality and the net counterparty credit exposure by industry sector. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market and Normal Purchase Normal Sale, or NPNS, and non-derivative transactions. The exposure is shown net of collateral held, and includes amounts net of receivables or payables.

	Net Exposure (a)
Category	(% of Total)
Financial institutions		67	%
Utilities, energy, merchants, marketers and other		30
Coal suppliers		1
ISOs		2
Total as of March 31, 2010		100	%

	Net Exposure (a)
Category	(% of Total)
Investment grade		80	%
Non-Investment grade		1
Non-rated		19
Total as of March 31, 2010		100	%

(a) Counterparty credit exposure excludes California tolling, Northeast load obligations, New England Reliability Must-Run, or RMR, certain cooperative load contracts, and Texas Westmoreland coal contracts. The aforementioned exposures were excluded for various reasons including regulatory support or liens held against the contracts which serve to reduce the risk of loss. NRG also excludes uranium and coal transportation contracts from counterparty credit exposure because of the illiquidity of the reference markets. Credit exposure also excludes any exposure NRG has to counterparties of non-recourse subsidiaries.

     NRG has counterparty credit risk exposure to certain counterparties representing more than 10% of total net exposure and the aggregate of such counterparties was $399 million. Approximately 82% of NRG’s positions relating to credit risk roll-off by the end of 2012. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration. Given the credit quality, diversification and term of the exposure in the portfolio, NRG does not anticipate a material impact on the Company’s financial results or results of operations from nonperformance by any of NRG’s counterparties.

  Retail Customer Credit Risk

     NRG is exposed to retail credit risk through the Company’s competitive electricity supply business, which serves C&I customers and the Mass market in Texas. Retail credit risk results when a customer fails to pay for services rendered. The losses could be incurred from nonpayment of customer accounts receivable and any 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, 2010, the Company’s retail customer credit exposure to C&I customers was diversified across many customers and various industries, with a significant portion of the exposure with government entities.

17

     NRG is also exposed to retail customer credit risk relating to its 1.5 million Mass customers, which may result in a write-off of bad debt. During the quarter, the Company experienced improved customer payment behavior, but current economic conditions may affect the Company’s customers’ ability to pay bills in a timely manner, which could increase customer delinquencies and may lead to an increase in bad debt expense.

     This footnote should be read in conjunction with the complete description under Note 5, Fair Value of Financial Instruments, to the Company’s financial statements in its Annual Report on Form 10-K for the year ended December 31, 2009.

Note 6 — Nuclear Decommissioning Trust Fund

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

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

	As of March 31, 2010								As of December 31, 2009
							Weighted-								Weighted-
							average								average
	Fair		Unrealized		Unrealized		maturities		Fair		Unrealized		Unrealized		maturities
(In millions, except otherwise noted)	Value		gains		losses		(in years)		Value		gains		losses		(in years)
Cash and cash equivalents	$	8	$	—	$	—		—	$	4	$	—	$	—		—
U.S. government and federal agency obligations		21		1		—		8		23		1		—		8
Federal agency mortgage-backed securities		63		2		—		22		60		2		—		23
Commercial mortgage-backed securities		9		—		1		29		10		—		1		29
Corporate debt securities		48		3		1		9		48		3		1		10
Marketable equity securities		231		99		1		—		220		89		2		—
Foreign government fixed income securities		2		—		—		7		2		—		—		6
Total	$	382	$	105	$	3			$	367	$	95	$	4

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

	Three months ended March 31,
(In millions)	2010		2009
Realized gains	$	1	$	2
Realized losses		1		8
Proceeds from sale of securities		67		78

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Note 7 — Accounting for Derivative Instruments and Hedging Activities

     ASC 815 requires NRG to recognize all derivative instruments on the balance sheet as either assets or liabilities and to measure them at fair value each reporting period unless they qualify for a NPNS exception. If certain conditions are met, NRG may be able to designate certain derivatives as cash flow hedges and defer the effective portion of the change in fair value of the derivatives to accumulated OCI, until the hedged transactions occur and are recognized in earnings. The ineffective portion of a cash flow hedge is immediately recognized in earnings.

     For derivatives designated as hedges of the fair value of assets or liabilities, the changes in fair value of both the derivative and the hedged transaction are recorded in current earnings.

     For derivatives that are not designated as cash flow hedges or do not qualify for hedge accounting treatment, the changes in the fair value will be immediately recognized in earnings. Under the guidelines established per ASC 815, certain derivative instruments may qualify for the NPNS exception and are therefore exempt from fair value accounting treatment. ASC 815 applies to NRG’s energy related commodity contracts, interest rate swaps, and foreign exchange contracts.

     As the Company engages principally in the trading and marketing of its generation assets and retail business, some of NRG’s commercial activities qualify for hedge accounting under the requirements of ASC 815. In order for the generation assets to qualify, the physical generation and sale of electricity should be highly probable at inception of the trade and throughout the period it is held, as is the case with the Company’s baseload plants. For this reason, many trades in support of NRG’s baseload units normally qualify for NPNS or cash flow hedge accounting treatment, and trades in support of NRG’s peaking unit’s asset optimization will generally not qualify for hedge accounting treatment, with any changes in fair value likely to be reflected on a mark-to-market basis in the statement of operations. Most of the retail load contracts either qualify for the NPNS exception or fail to meet the criteria for a derivative and the majority of the supply contracts are recorded under mark-to-market accounting. All of NRG’s hedging and trading activities are subject to limits within the Company’s Risk Management Policy.

  Energy-Related Commodities

     To manage the commodity price risk associated with the Company’s competitive supply activities and the price risk associated with wholesale and retail power sales from the Company’s electric generation facilities, NRG may enter into a variety of derivative and non-derivative hedging instruments, utilizing the following:

• Forward contracts, which commit NRG to sell or purchase energy commodities or purchase fuels in the future.

• Futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial instrument.

• Swap agreements, which require payments to or from counter-parties based upon the differential between two prices for a predetermined contractual, or notional, quantity.

• Option contracts, which convey the right or obligation to purchase or sell a commodity.

• Weather and hurricane derivative products used to mitigate a portion of Reliant Energy’s lost revenue due to weather.

     As of March 31, 2010, NRG had cash flow hedge energy-related derivative financial instruments extending through December 2013. The objectives for entering into derivative contracts designated as hedges include:

• Fixing the price for a portion of anticipated future electricity sales through the use of various derivative instruments including gas collars and swaps at a level that provides an acceptable return on the Company’s electric generation operations.

• Fixing the price of a portion of anticipated fuel purchases for the operation of NRG’s power plants.

     NRG’s trading activities are subject to limits within the Company’s Risk Management Policy. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings.

19

  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, 2010, NRG had interest rate derivative instruments extending through June 2019, all of which had been designated as either cash flow or fair value hedges.

  Volumetric Underlying Derivative Transactions

     The following table summarizes the net notional volume buy/(sell) of NRG’s open derivative transactions broken out by commodity, excluding those derivatives that qualified for the NPNS exception as of March 31, 2010, and December 31, 2009. Option contracts are reflected using delta volume. Delta volume equals the notional volume of an option adjusted for the probability that the option will be in-the-money at its expiration date.

		Total Volume
		March 31,			December 31,
		2010			2009
Commodity	Units	(In millions)
Emissions	Short Ton		(6	)		(2	)
Coal	Short Ton		49			55
Natural Gas	MMBtu		(250	)		(484	)
Oil	Barrel		1			1
Power(a)	MWH		(41	)		(41	)
Interest	Dollars	$	3,101		$	3,291

(a) Power volumes include capacity sales.

Fair Value of Derivative Instruments

     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. The Company has chosen not to offset positions as permitted in ASC 815. As of March 31, 2010, the Company recorded $533 million of cash collateral paid and $509 million of cash collateral received on its balance sheet.

     The following table summarizes the fair value within the derivative instrument valuation on the balance sheet as of March 31, 2010, and December 31, 2009:

	Fair Value
	Derivatives Asset				Derivatives Liability
	March 31,		December 31,		March 31,		December 31,
(In millions)	2010		2009		2010		2009
Derivatives Designated as Cash Flow or Fair Value Hedges:
Interest rate contracts current	$	—	$	—	$	65	$	2
Interest rate contracts long-term		11		8		43		106
Commodity contracts current		521		300		12		12
Commodity contracts long-term		759		508		2		6
Total Derivatives Designated as Cash Flow or Fair Value Hedges		1,291		816		122		126
Derivatives Not Designated as Cash Flow or Fair Value Hedges:
Commodity contracts current		2,203		1,336		2,277		1,459
Commodity contracts long-term		205		167		394		275
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges		2,408		1,503		2,671		1,734
Total Derivatives	$	3,699	$	2,319	$	2,793	$	1,860

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Impact of Derivative Instruments on the Statement of Operations

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

Amount of gain/(loss) recognized	Three months ended March 31,
(In millions)	2010			2009
Derivative	$	3		$	(1	)
Senior Notes (hedged item)	$	(3	)	$	1

     The following table summarizes the location and amount of gain/(loss) resulting from cash flow hedges:

					Amount of				Amount of
	Amount of			Location of	gain/(loss)			Location of	gain/(loss)
	gain/(loss)			gain/(loss)	reclassified from			gain/(loss)	recognized in
	recognized in OCI			reclassified from	Accumulated			recognized in	income
(In millions)	(effective portion)			Accumulated	OCI into Income			income	(ineffective
Three months ended March 31, 2010	after tax			OCI into Income	after tax			(ineffective portion)	portion)
Interest rate contracts	$	(1	)	Interest expense	$	(2	)	Interest expense	$	—
Commodity contracts		258		Operating revenue		106		Operating revenue		(2	)
Total	$	257			$	104			$	(2	)

				Amount of				Amount of
	Amount of		Location of	gain/(loss)			Location of	gain/(loss)
	gain/(loss)		gain/(loss)	reclassified from			gain/(loss)	recognized in
	recognized in OCI		reclassified from	Accumulated			recognized in	income
(In millions)	(effective portion)		Accumulated	OCI into Income			income	(ineffective
Three months ended March 31, 2009	after tax		OCI into Income	after tax			(ineffective portion)	portion)
Interest rate contracts	$	12	Interest expense	$	(1	)	Interest expense	$	—
Commodity contracts		161	Operating revenue		245		Operating revenue		4
Total	$	173		$	244			$	4

     The following table summarizes the amount of gain/(loss) recognized in income for derivatives not designated as cash flow or fair value hedges on commodity contracts:

Amount of gain/(loss) recognized in income or cost of operations for derivatives	Three months ended March 31,
(In millions)	2010			2009
Location of gain/(loss) recognized in income for derivatives:
Operating revenue	$	71		$	323
Cost of operations	$	(107	)	$	(52	)

Credit Risk Related Contingent Features

     Certain of the Company’s hedging agreements contain provisions that require the Company to post additional collateral if the counterparty determines that there has been deterioration in credit quality, generally termed “adequate assurance” under the agreements, or require the Company to post additional collateral if there was a one notch downgrade in the Company’s credit rating. The collateral required for contracts that have adequate assurance clauses that are in a net liability position as of March 31, 2010, was $42 million. The collateral required or contracts with credit rating contingent features that are in a net liability position as of March 31, 2010, was $16 million. The Company is also a party to certain marginable agreements where NRG has a net liability position but the counterparty has not called for the collateral due, which is approximately $7 million as of March 31, 2010.

     On April 28, 2010, Merrill Lynch agreed to continue to provide credit support to four Reliant Energy counterparties under the Amended CSRA through December 15, 2010. The Company intends to have no Reliant Energy counterparties under the Amended CSRA by December 15, 2010.

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

21

  Accumulated Other Comprehensive Income

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

(In millions)	Energy			Interest
Three months ended March 31, 2010	Commodities			Rate			Total
Accumulated OCI balance at December 31, 2009	$	461		$	(55	)	$	406
Realized from OCI during the period:
- Due to realization of previously deferred amounts		(106	)		2			(104	)
Mark-to-market of cash flow hedge accounting contracts		364			(3	)		361
Accumulated OCI balance at March 31, 2010, net of $398 tax	$	719		$	(56	)	$	663
Gains/(losses) expected to be realized from OCI during the next 12 months, net of $228 tax	$	432		$	(43	)	$	389

(In millions)	Energy			Interest
Three months ended March 31, 2009	Commodities			Rate			Total
Accumulated OCI balance at December 31, 2008	$	406		$	(91	)	$	315
Realized from OCI during the period:
- Due to realization of previously deferred amounts		(112	)		1			(111	)
- Due to discontinuation of cash flow hedge accounting		(133	)		—			(133	)
Mark-to-market of cash flow hedge accounting contracts		406			11			417
Accumulated OCI balance at March 31, 2009, net of $305 tax	$	567		$	(79	)	$	488

     Accounting guidelines require a high degree of correlation between the derivative and the hedged item throughout the period in order to qualify as a cash flow hedge. As of July 31, 2008, the Company’s regression analysis for natural gas prices to ERCOT power prices, while positively correlated, did not meet the required threshold for cash flow hedge accounting for calendar years 2012 and 2013. As a result, the Company de-designated its 2012 and 2013 ERCOT cash flow hedges as of July 31, 2008, and prospectively marked these derivatives to market. On April 1, 2009, the required correlation threshold for cash flow hedge accounting was achieved for these transactions, and accordingly, these hedges were re-designated as cash flow hedges.

     As discussed in Note 3, Acquisitions, to the Company’s financial statements in its Annual Report on Form 10-K for the year ended December 31, 2009, on October 5, 2009, the Company amended the CSRA with Merrill Lynch. In connection with the CSRA Amendment, NRG net settled certain in-the-money transactions with Morgan Stanley. As these transactions were net settled, $245 million in accumulated OCI was frozen and will be recognized into income when the underlying power from the baseload plants is generated.

     Statement of Operations

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

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

	Three months ended
	March 31,
(In millions)	2010			2009
Unrealized mark-to-market results
Reversal of previously recognized unrealized gains on settled positions related to economic hedges	$	(40	)	$	(16	)
Reversal of loss positions acquired as part of the Reliant Energy acquisition as of May 1, 2009		90			—
Reversal of previously recognized unrealized losses/(gains) on settled positions related to trading activity		18			(69	)
Net unrealized (losses)/gains on open positions related to economic hedges		(118	)		349
(Losses)/gains on ineffectiveness associated with open positions treated as cash flow hedges		(2	)		4
Net unrealized gains on open positions related to trading activity		14			7
Total unrealized (losses)/gains	$	(38	)	$	275

	Three months ended
	March 31,
(In millions)	2010			2009
Revenue from operations — energy commodities	$	69		$	327
Cost of operations		(107	)		(52	)
Total impact to statement of operations	$	(38	)	$	275

     Reliant Energy’s loss positions were acquired as of May 1, 2009, and valued using forward prices on that date. The $90 million roll-off amounts were offset by realized losses at the settled prices and are reflected in the cost of operations during the same period.

     The $118 million loss from economic hedge positions is the result of a decrease in value of forward purchases and sales of natural gas, electricity and fuel due to decrease in forward power and gas prices.

     For the period ended March 31, 2009, the $349 million gain from economic hedge positions includes $217 million recognized in earnings from previously deferred amounts in accumulated OCI as the Company discontinued cash flow hedge accounting for certain 2009 transactions in Texas and New York due to lower expected generation, and $132 million of increase in value of forward sales of electricity and fuel due to forward power and gas prices. The $4 million gain is primarily from hedge accounting ineffectiveness related to gas trades in Texas which was driven by decreasing forward gas prices while forward power prices decreased at a slower pace.

     Discontinued Normal Purchase and Sale for Coal Purchases — Due to lower coal-fired generation during the first quarter 2009, the Company’s coal consumption was lower than forecasted. The Company net settled some of its coal purchases under NPNS designation and thus was no longer able to assert physical delivery under these coal contracts. The forward positions previously treated as accrual accounting were reclassified into mark-to-market accounting during the first quarter and prospectively. The impact of discontinuance of coal NPNS designated transactions resulted in a derivative loss of $29 million that was reflected in the cost of operations for the three months ended March 31, 2009.

Note 8 — Long-Term Debt

   Senior Credit Facility

     In March 2010, NRG made a repayment of approximately $229 million to its first lien lenders under the Term Loan Facility. This payment resulted from the mandatory annual offer of a portion of NRG’s excess cash flow (as defined in the Senior Credit Facility) for the prior year.

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  Debt Related to Capital Allocation Program

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

     Dunkirk Power LLC Tax-Exempt Bonds

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

     GenConn Energy LLC related financings

     NRG Connecticut Peaking Development LLC made funding requests under the equity bridge loan, or EBL, during the quarter. The EBL is backed by a letter of credit issued by NRG under its Synthetic Letter of Credit Facility equal to 104% of the amount outstanding. The proceeds of the EBL received through March 31, 2010, were $114 million and the remaining amounts will be drawn as necessary to fund interest on the EBL as the maximum amount permitted to be drawn for project costs for both projects has been met.

     Borrowings of an equity method investment — In April 2009, GenConn secured financing for 50% of the Devon and Middletown project construction costs through a seven-year term loan facility, and also entered into a five-year revolving working capital loan and letter of credit facility, which collectively with the term loan is referred to as the GenConn Facility. The aggregate credit amount secured under the GenConn Facility, which is non-recourse to NRG, is $291 million, including $48 million for the revolving facility. In August 2009, GenConn began to draw under the GenConn Facility to cover costs related to the Devon project. As of March 31, 2010, $75 million had been drawn.

Note 9 — Changes in Capital Structure

     The following table reflects the changes in NRG’s common stock issued and outstanding during the three months ended March 31, 2010:

	Authorized		Issued		Treasury			Outstanding
Balance as of December 31, 2009		500,000,000		295,861,759		(41,866,451	)		253,995,308
Shares issued under LTIP		—		150,853		—			150,853
Shares issued under NRG Employee Stock Purchase Plan, or ESPP		—		—		54,845			54,845
Shares returned by affiliate of CS		—		—		(6,600,000	)		(6,600,000	)
4% Preferred Stock conversion		—		7,701,450		—			7,701,450
Balance as of March 31, 2010		500,000,000		303,714,062		(48,411,606	)		255,302,456

  Employee Stock Purchase Plan

     As of March 31, 2010, there were 363,623 shares of treasury stock reserved for issuance under the ESPP.

  4% Preferred Stock

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

  Share Lending Agreements

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

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Note 10 — Equity Compensation

   Non-Qualified Stock Options, or NQSOs

     The following table summarizes the Company’s NQSO activity as of March 31, 2010, and changes during the three months then ended:

				Weighted		Aggregate Intrinsic
				Average		Value
	Shares			Exercise Price		(In millions)
Outstanding as of December 31, 2009		4,793,585		$	25.07
Granted		754,200			23.79
Exercised		(109,165	)		22.15
Forfeited		(214,241	)		30.82
Outstanding at March 31, 2010		5,224,379			24.71	$	10
Exercisable at March 31, 2010		3,302,851		$	23.68	$	10

     The weighted average grant date fair value of NQSOs granted for the three months ended March 31, 2010, was $10.67.

     Restricted Stock Units, or RSUs

     The following table summarizes the Company’s non-vested RSU awards as of March 31, 2010, and changes during the three months then ended:

				Weighted Average
				Grant-Date
	Units			Fair Value Per Unit
Non-vested as of December 31, 2009		1,614,769		$	30.78
Granted		352,600			23.66
Vested		(65,000	)		27.92
Forfeited		(65,570	)		30.12
Non-vested as of March 31, 2010		1,836,799		$	29.53

  Performance Units, or PUs

     The following table summarizes the Company’s non-vested PU awards as of March 31, 2010, and changes during the three months then ended:

				Weighted Average
				Grant- Date
	Units			Fair Value Per Unit
Non-vested as of December 31, 2009		617,300		$	24.27
Granted		348,500			23.81
Forfeited		(172,200	)		22.20
Non-vested as of March 31, 2010		793,600		$	24.52

     In the three months ended March 31, 2010, there were no performance unit payouts in accordance with the terms of the performance units.

  Deferral Stock Units, or DSUs

     The following table summarizes the Company’s outstanding DSU awards as of March 31, 2010, and changes during the three months then ended:

				Weighted Average
				Grant- Date
	Units			Fair Value Per Unit
Outstanding as of December 31, 2009		304,049		$	19.34
Granted		—			—
Conversions		(1,012	)		21.72
Outstanding as of March 31, 2010		303,037		$	19.33

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Note 11 — Earnings Per Share

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

     Diluted earnings per share attributable to NRG common stockholders is computed in a manner consistent with that of basic earnings per share while giving effect to all potentially dilutive common shares that were outstanding during the period.

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

     The reconciliation of NRG’s basic earnings per common share to diluted earnings per share for the three months ended March 31, 2010, and 2009 is shown in the following table:

	Three months ended March 31,
(In millions, except per share data)	2010			2009
Basic earnings per share attributable to NRG common stockholders
Numerator:
Net income attributable to NRG Energy, Inc.	$	58		$	198
Preferred stock dividends		(2	)		(14	)
Net income attributable to NRG Energy, Inc. available to common stockholders	$	56		$	184
Denominator:
Weighted average number of common shares outstanding		253.8			237.1
Basic earnings per share:
Net income attributable to NRG Energy, Inc.	$	0.22		$	0.78
Diluted earnings per share attributable to NRG common stockholders
Numerator:
Net income available to common stockholders	$	56		$	184
Add preferred stock dividends for dilutive preferred stock		—			10
Net income attributable to NRG Energy, Inc. available to common stockholders	$	56		$	194
Denominator:
Weighted average number of common shares outstanding		253.8			237.1
Incremental shares attributable to the issuance of equity compensation (treasury stock method)		1.2			1.0
Incremental shares attributable to assumed conversion features of outstanding preferred stock (if-converted method)		1.5			37.3
Total dilutive shares		256.5			275.4
Diluted earnings per share:
Net income attributable to NRG Energy, Inc.	$	0.22		$	0.70

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

	Three months ended March 31,
(In millions of shares)	2010		2009
Equity compensation — NQSOs and PUs		6.1		5.4
Embedded derivative of 3.625% redeemable perpetual preferred stock		16.0		16.0
Embedded derivatives of CSF II Debt		—		7.6
Total		22.1		29.0

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Note 12 — Segment Reporting

     NRG’s segment structure reflects core areas of operation which are primarily segregated based on the Company’s wholesale power generation, retail, thermal and chilled water business, and corporate activities. In May 2009, NRG’s segment structure changed to reflect the Company’s acquisition of Reliant Energy, which has been incorporated as a separate reporting segment per ASC-280, Segment Reporting. Within NRG’s wholesale power generation operations, there are distinct components with separate operating results and management structures for the following geographical regions: Texas, Northeast, South Central, West and International. The Company’s corporate activities include wind, solar and nuclear development.

     In the second quarter 2009, management changed its method for allocating corporate general and administrative expenses to the segments. Corporate general and administrative expenses had been allocated based on budgeted segment revenues. Beginning in the second quarter 2009, corporate general and administrative expenses have been allocated based on forecasted earnings/(losses) before interest expense, income taxes, depreciation and amortization expense.

(In millions)				Wholesale Power Generation
Three months ended	Reliant							South
March 31, 2010	Energy			Texas (a)		Northeast		Central			West		International		Thermal		Corporate			Elimination			Total
Operating revenues	$	1,176		$	870	$	279	$	143		$	35	$	35	$	36	$	2		$	(361	)	$	2,215
Depreciation and amortization		30			117		32		16			3		—		2		2			—			202
Equity in earnings of unconsolidated affiliates		—			10		—		—			—		4		—		—			—			14
Income/(loss) before income taxes		(188	)		375		52		(4	)		6		10		4		(132	)		—			123
Net income/(loss) attributable to NRG Energy, Inc.	$	(188	)	$	375	$	52	$	(4	)	$	6	$	8	$	4	$	(195	)	$	—		$	58
Total assets	$	1,910		$	13,936	$	1,871	$	891		$	357	$	769	$	206	$	23,932		$	(19,294	)	$	24,578

(a) Includes inter-segment sales of $360 million, comprised of $216 million of inter-segment physical sales, $135 million inter-segment unrealized gains on derivatives and $9 million of financial revenue on derivatives with Reliant Energy.

     If the Company continued using the previous allocation method for corporate general and administrative expenses, the effect to net income/(loss) of each segment for the three months ended March 31, 2010, would have been as follows:

Net income/(loss) attributable to NRG Energy, Inc. as reported	$	(188	)	$	375	$	52	$	(4	)	$	6	$	8	$	4	$	(195	)	$	—	$	58
Increase/(decrease) in net income/(loss) attributable to NRG Energy, Inc.		(11	)		10		2		(1	)		—		—		—		—			—		—
Adjusted net income/(loss) attributable to NRG Energy, Inc.	$	(199	)	$	385	$	54	$	(5	)	$	6	$	8	$	4	$	(195	)	$	—	$	58

(In millions)	Wholesale Power Generation
Three months ended					South
March 31, 2009	Texas		Northeast		Central		West			International		Thermal		Corporate			Elimination			Total
Operating revenues	$	925	$	464	$	162	$	28		$	34	$	42	$	4		$	(1	)	$	1,658
Depreciation and amortization		117		29		17		2			—		2		2			—			169
Equity in earnings of unconsolidated affiliates		4		—		—		1			17		—		—			—			22
Income/(loss) from continuing operations before income taxes		378		211		1		(3	)		14		4		(109	)		—			496
Net income/(loss) attributable to NRG Energy, Inc.	$	217	$	211	$	1	$	(3	)	$	12	$	4	$	(244	)	$	—		$	198

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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)	2010			2009
Income tax expense	$	65		$	298
Effective tax rate		52.7	%		60.0	%

     For the three months ended March 31, 2010, NRG’s overall effective tax rate was different than the statutory rate of 35% primarily due to state and local income taxes as well as recording federal and state tax expense and interest for unrecognized tax benefits. For the three months ended March 31, 2009, NRG’s effective tax rate was increased primarily due to the impact of state and local income taxes in addition to an increase in valuation allowance as a result of capital losses generated in the quarter for which there were no projected capital gains or available tax planning strategies.

  Unrecognized tax benefits

     As of March 31, 2010, NRG has recorded a $423 million non-current tax liability for unrecognized tax benefits, primarily resulting from taxable earnings for the period for which there are no net operating losses available to offset for financial statement purposes. NRG has accrued interest related to these unrecognized tax benefits of approximately $14 million for the three months ended March 31, 2010, and has accrued approximately $31 million since adoption. The Company recognizes interest and penalties related to unrecognized tax benefits in income tax expense.

     The Company continues to be under examination by the Internal Revenue Service for the years 2004 through 2006.

  Tax Receivable and Payable

     As of March 31, 2010, NRG recorded a current tax payable of approximately $40 million that represents a tax liability due for domestic state taxes of approximately $28 million, as well as foreign taxes payable of approximately $12 million. In addition, NRG has a domestic tax receivable of $153 million, of which $102 million reflects federal cash grants receivable for the Blythe solar and Langford wind facilities.

Note 14 — Benefit Plans and Other Postretirement Benefits

   NRG Defined Benefit Plans

     NRG sponsors and operates three defined benefit pension and other postretirement plans. The NRG Plan for Bargained Employees and the NRG Plan for Non-Bargained Employees are maintained solely for eligible legacy NRG participants. A third plan, the Texas Genco Retirement Plan, is maintained for participation solely by eligible employees. The total amount of employer contributions paid for the three months ended March 31, 2010, was $5 million. NRG expects to make approximately $13 million in further contributions for the remainder of 2010.

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

	Defined Benefit Pension
(In millions)	Plans
Three months ended March 31,	2010			2009
Service cost benefits earned	$	3		$	4
Interest cost on benefit obligation		5			5
Expected return on plan assets		(4	)		(4	)
Net periodic benefit cost	$	4		$	5

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     The net periodic cost related to all of the Company’s other post retirement benefits plans include the following components:

	Other Postretirement
(In millions)	Benefits Plans
Three months ended March 31,	2010		2009
Service cost benefits earned	$	1	$	1
Interest cost on benefit obligation		1		2
Net periodic benefit cost	$	2	$	3

  STP Defined Benefit Plans

     NRG has a 44% undivided ownership interest in STP. South Texas Project Nuclear Operating Company, or STPNOC, which operates and maintains STP, provides its employees a defined benefit pension plan as well as postretirement health and welfare benefits. Although NRG does not sponsor the STP plan, it reimburses STPNOC for 44% of the contributions made towards its retirement plan obligations. There were no employer contributions reimbursed to STPNOC for the three months ended March 31, 2010. The Company recognized net periodic costs related to its 44% interest in STP defined benefits plans of $2 million and $3 million for the three months ended March 31, 2010, and 2009, respectively.

Note 15 — Commitments and Contingencies

   First and Second Lien Structure

     NRG has granted first and second liens to certain counterparties on substantially all of the Company’s assets to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or MWh equivalents. The Company’s lien counterparties may have a claim on NRG’s assets to the extent market prices exceed the hedged price. As of March 31, 2010, and April 23, 2010, all hedges under the first and second liens were in-the-money on a counterparty aggregate basis.

  RepoweringNRG Initiatives

     NRG has capitalized $33 million through March 31, 2010, for the repowering of its El Segundo generating facility in California. Air permitting litigation unrelated to the El Segundo project has delayed receipt of certain required permits, including an air permit, which will prevent the El Segundo project from meeting its original completion date of June 2011. Legislation enacted on January 1, 2010 has allowed the affected air district to issue air permits like El Segundo’s. A revised draft air permit was issued in April 2010, allowing the project permitting to proceed. The Company is working with the counterparty to consider certain PPA modifications including the commercial operations date, currently expected to be the summer of 2013.

Contingencies

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

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

  California Department of Water Resources

     This matter concerns, among other contracts and other defendants, the California Department of Water Resources, or CDWR and its wholesale power contract with subsidiaries of WCP (Generation) Holdings, Inc., or WCP. The case originated with a February 2002 complaint filed by the State of California alleging that many parties, including WCP subsidiaries, overcharged the State of California. For WCP, the alleged overcharges totaled approximately $940 million for 2001 and 2002. The complaint demanded that the Federal Energy Regulatory Commission, or FERC abrogate the CDWR contract and sought refunds associated with revenues collected under the contract. In 2003, the FERC rejected this complaint, denied rehearing, and the case was appealed to the U.S. Court of Appeals for the Ninth Circuit where oral argument was held on December 8, 2004. On December 19, 2006, the Ninth Circuit decided that in the FERC’s review of the contracts at issue, the FERC could not rely on the Mobile-Sierra standard presumption of just and reasonable rates, where such contracts were not reviewed by the FERC with full knowledge of the then existing market conditions. WCP and others sought review by the U.S. Supreme Court. WCP’s appeal was not selected, but instead held by the Supreme Court. In the appeal that was selected by the Supreme Court, on June 26, 2008 the Supreme Court ruled: (i) that the Mobile-Sierra public interest standard of review applied to contracts made under a seller’s market-based rate authority; (ii) that the public interest “bar” required to set aside a contract remains a very high one to overcome; and (iii) that the Mobile-Sierra presumption of contract reasonableness applies when a contract is formed during a period of market dysfunction unless (a) such market conditions were caused by the illegal actions of one of the parties or (b) the contract negotiations were tainted by fraud or duress. In this related case, the U.S. Supreme Court affirmed the Ninth Circuit’s decision agreeing that the case should be remanded to the FERC to clarify the FERC’s 2003 reasoning regarding its rejection of the original complaint relating to the financial burdens under the contracts at issue and to alleged market manipulation at the time these contracts were formed. As a result, the U.S. Supreme Court then reversed and remanded the WCP CDWR case to the Ninth Circuit for treatment consistent with its June 26, 2008 decision in the related case. On October 20, 2008, the Ninth Circuit asked the parties in the remanded CDWR case, including WCP and the FERC, whether that Court should answer a question the U.S. Supreme Court did not address in its June 26, 2008, decision; whether the Mobile-Sierra doctrine applies to a third-party that was not a signatory to any of the wholesale power contracts, including the CDWR contract, at issue in that case. Without answering that reserved question, on December 4, 2008, the Ninth Circuit vacated its prior opinion and remanded the WCP CDWR case back to the FERC for proceedings consistent with the U.S. Supreme Court’s June 26, 2008, decision. On December 15, 2008, WCP and the other seller-defendants filed with the FERC a Motion for Order Governing Proceedings on Remand. On January 14, 2009, the Public Utilities Commission of the State of California filed an Answer and Cross Motion for an Order Governing Procedures on Remand and on January 28, 2009, WCP and the other seller-defendants filed their reply.

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

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

  Louisiana Generating, LLC

     On February 11, 2009, the U.S. Department of Justice 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

30

allowances or credits; (v) conduct audits to determine if any additional modifications have been made which would require compliance with the CAA’s Prevention of Significant Deterioration program; (vi) award to the Department of Justice its costs in prosecuting this litigation; and (vii) assess civil penalties of up to $27,500 per day for each CAA violation found to have occurred between January 31, 1997, and March 15, 2004, up to $32,500 for each CAA violation found to have occurred between March 15, 2004, and January 12, 2009, and up to $37,500 for each CAA violation found to have occurred after January 12, 2009.

     On April 27, 2009, LaGen made several filings. It 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. It also filed a complaint in the same bankruptcy proceeding in the same court 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; and (iii) Cajun Electric and/or the Bankruptcy Trustee are exclusively liable for the violations alleged in the February 11, 2009, lawsuit to the extent that such claims are determined to have merit. On June 8, 2009, the parties filed a joint status report setting forth their views of the case and proposing a trial schedule. On June 18, 2009, LaGen filed a motion to bifurcate the Department of Justice lawsuit into separate liability and remedy phases, and on June 30, 2009, the Department of Justice filed its opposition. On August 24, 2009, LaGen filed a motion to dismiss this lawsuit, and on September 25, 2009, the Department of Justice filed its opposition to the motion to dismiss. On April 15, 2010, the bankruptcy court signed an order granting LaGen’s stipulation of voluntary dismissal without prejudice of its adversary bankruptcy action.

     On February 18, 2010, the 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 Department of Justice. On February 19, 2010, the district court granted LDEQ’s motion to intervene. On April 26, 2010, LaGen filed a motion to dismiss LDEQ’s complaint. On April 28, 2010, the district court entered a Joint Case Management Order in this matter. As a result of entering this order, LaGen’s motion for bifurcation was effectively granted. As such, the first trial on liability will take place on or about May 2011. The second trial on the remedy will take place on or about March 2012.

  Nuclear Innovation North America, LLC

     On December 6, 2009, CPS commenced a lawsuit against two NINA entities asking the court to declare the rights, obligations, and remedies of the parties pursuant to the 1997 and 2007 agreements between the parties should CPS unilaterally withdraw from the proposed STP Units 3 and 4 Project. On December 23, 2009, and on two occasions thereafter, CPS amended its original December 6 complaint adding NRG, Toshiba Corporation, and NINA as defendants and not only continued to request that the court declare the rights, obligations, and remedies of the parties under the two operative governing agreements, but also sought $32 billion in damages. The amended complaint alleged that NRG, Toshiba, and NINA had been involved in a conspiracy to defraud CPS, that they purposefully misled CPS in inducing it to be a partner in the STP Units 3 and 4 Project, that they maliciously interfered with CPS contracts and business relationships, and that they willfully disparaged CPS. On March 1, 2010, NINA and CPS entered into a Project Agreement, Settlement Agreement and Mutual Release. As part of the agreement, NINA increased its ownership in the STP Units 3 and 4 Project from 50% to 92.375% and assumed full management control of the Project. NRG also will pay $80 million to CPS, subject to receipt of a conditional U.S. DOE loan guarantee. The first $40 million would be promptly paid after receipt of the guarantee with the remaining $40 million paid six months later. An additional $10 million will be donated by NRG over four years in annual payments of $2.5 million to the Residential Energy Assistance Partnership, or REAP, in San Antonio. The first $2.5 million payment to REAP was made on March 17, 2010. In connection with the agreement, the Company capitalized $90 million to construction in progress within property, plant and equipment, and as of March 31, 2010, $80 million in other current liabilities and $7.5 million in other non-current liabilities remains on the condensed consolidated balance sheet for the obligations to CPS and REAP. On March 2, 2010, the court entered an agreed order dismissing the case with prejudice, thereby ending the litigation.

  Dunkirk Construction Litigation

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

     On August 28, 2009, Hohl filed its original complaint against NRG, its subsidiary Dunkirk Power LLC, or Dunkirk Power, and CBEEC among others for claims of breach of contract, quantum meruit, unjust enrichment and foreclosure of mechanics’ liens. As part of CBEEC’s contractual obligation to NRG, CBEEC agreed to defend NRG, under a reservation of rights. CBEEC filed an answer to the above complaint on behalf of itself, NRG, and Dunkirk Power on October 5, 2009. On December 16, 2009, CBEEC filed a Motion for Summary Judgment on behalf of itself, NRG, and Dunkirk Power. On February 1, 2010, NRG and Dunkirk Power

31

filed a Motion for Leave to file an Amended Answer with Cross-Claims against CBEEC. NRG asserted breach of contract claims seeking liquidated damages for the delays caused by CBEEC. NRG also retained its own counsel to represent its interest in the cross-claims and reserved its rights to seek reimbursement from CBEEC. On February 17, 2010, CBEEC filed an Amended Answer with Affirmative Defenses, Counterclaims and Cross-Claims against NRG, in which it sought $30 million alleging breach of contract, quantum meruit, unjust enrichment, and foreclosure of two mechanic’s liens, as a result of alleged delays caused by NRG and Dunkirk Power. On March 5, 2010, CBEEC and NRG resolved their disputed cross-claims. In April 2010, the other parties to this litigation settled their disputes which settlement is expected to be final in the third quarter of 2010.

  Excess Mitigation Credits

     From January 2002 to April 2005, CenterPoint Energy applied excess mitigation credits, or EMCs, to its monthly charges to retail electric providers as ordered by the Public Utility Commission of Texas, or PUCT. The PUCT imposed these credits to facilitate the transition to competition in Texas, which had the effect of lowering the retail electric providers’ monthly charges payable to CenterPoint Energy. As indicated in its Petition for Review filed with the Supreme Court of Texas on June 2, 2008, CenterPoint Energy has claimed that the portion of those EMCs credited to Reliant Energy Retail Services, LLC, or RERS, a retail electric provider and NRG subsidiary acquired from RRI, totaled $385 million for RERS’s “Price to Beat” Customers. It is unclear what the actual number may be. “Price to Beat” was the rate RERS was required by state law to charge residential and small commercial customers that were transitioned to RERS from the incumbent integrated utility company commencing in 2002. In its original stranded cost case brought before the PUCT on March 31, 2004, CenterPoint Energy sought recovery of all EMCs that were credited to all retail electric providers, including RERS, and the PUCT ordered that relief in its Order on Rehearing in Docket No. 29526, on December 17, 2004. After an appeal to state district court, the court entered a final judgment on August 26, 2005, affirming the PUCT’s order with regard to EMCs credited to RERS. Various parties filed appeals of that judgment with the Court of Appeals for the Third District of Texas with the first such appeal filed on the same date as the state district court judgment and the last such appeal filed on October 10, 2005. On April 17, 2008, the Court of Appeals for the Third District reversed the lower court’s decision ruling that CenterPoint Energy’s stranded cost recovery should exclude only EMCs credited to RERS for its “Price to Beat” customers. On June 2, 2008, CenterPoint Energy filed a Petition for Review with the Supreme Court of Texas and on June 19, 2009, the Court agreed to consider the CenterPoint Energy appeal as well as two related petitions for review filed by other entities. Oral argument occurred on October 6, 2009.

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

Note 16 — Regulatory Matters

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

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

     PJM — On June 18, 2009, FERC denied rehearing of its order dated September 19, 2008, dismissing a complaint filed by the Maryland Public Service Commission, or MDPSC, together with other load interests, against PJM challenging the results of the Reliability Pricing Model, or RPM transition Base Residual Auctions for installed capacity, held between April 2007 and January 2008. The complaint had sought to replace the auction-determined results for installed capacity for the 2008/2009, 2009/2010, and 2010/2011 delivery years with administratively-determined prices. On August 14, 2009, the MDPSC and the New Jersey Board of Public Utilities filed an appeal of FERC’s orders to the U.S. Court of Appeals for the Fourth Circuit, and a successful appeal could disrupt the auction-determined results and create a refund obligation for market participants. The case has been transferred to the U.S. Court of Appeals for the DC Circuit and is being briefed.

32

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

     Retail (Replacement Reserve) — On November 14, 2006, Constellation Energy Commodities Group, or Constellation, filed a complaint with the PUCT alleging that ERCOT misapplied the Replacement Reserve Settlement, or RPRS, Formula contained in the ERCOT protocols from April 10, 2006, through September 27, 2006. Specifically, Constellation disputed approximately $4 million in under-scheduling charges for capacity insufficiency asserting that ERCOT applied the wrong protocol. REPS, other market participants, ERCOT, and PUCT staff opposed Constellation’s complaint. On January 25, 2008, the PUCT entered an order finding that ERCOT correctly settled the capacity insufficiency charges for the disputed dates in accordance with ERCOT protocols and denied Constellation’s complaint. On April 9, 2008, Constellation appealed the PUCT order to the Civil District Court of Travis County, Texas and on June 19, 2009, the court issued a judgment reversing the PUCT order, finding that the ERCOT protocols were in irreconcilable conflict with each other. On July 20, 2009, REPS filed an appeal to the Third Court of Appeals in Travis County, Texas, thereby staying the effect of the trial court’s decision. If all appeals are unsuccessful, on remand to the PUCT, it would determine the appropriate methodology for giving effect to the trial court’s decision. It is not known at this time whether only Constellation’s under-scheduling charges, the under-scheduling charges of all other QSEs that disputed REPS charges for the same time frame, the entire market, or some other approach would be used for any resettlement.

     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.

Note 17 — Environmental Matters

     The construction and operation of power projects are subject to stringent environmental and safety protection and land use laws and regulation in the U.S. If such laws and regulations become more stringent, or new laws, interpretations or compliance policies apply and NRG’s facilities are not exempt from coverage, the Company could be required to make modifications to further reduce potential environmental impacts. New legislation and regulations to mitigate the effects of Greenhouse Gases, or GHG including Carbon dioxide, or CO₂ from power plants, are under consideration at the federal and state levels. In general, the effect of such future laws or regulations is expected to require the addition of pollution control equipment or the imposition of restrictions or additional costs on the Company’s operations.

  Environmental Capital Expenditures

     Based on current rules, technology and plans, NRG has estimated that environmental capital expenditures from 2010 through 2014 to meet NRG’s environmental commitments will be approximately $0.9 billion and are primarily associated with controls on the Company’s Big Cajun and Indian River facilities. These capital expenditures, in general, are related to installation of particulate, Sulfur dioxide, or SO₂, Nitrogen oxide, or NO_x, and mercury controls to comply with federal and state air quality rules and consent orders, as well as installation of “Best Technology Available” under a section of the Clean Water Act regulating cooling water intake structures, or Phase II 316(b) Rule. NRG continues to explore cost effective alternatives that can achieve desired results. This estimate reflects anticipated schedules and controls related to the Clean Air Interstate Rule, or CAIR, Maximum Achievable Control Technology, or MACT for mercury, and the Phase II 316(b) Rule which are under remand to the U.S. EPA, and, as such, the full impact on the scope and timing of environmental retrofits from any new or revised regulations cannot be determined at this time.

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

33

  Northeast Region

     In January 2006, NRG’s Indian River Operations, Inc. received a letter of informal notification from the 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 the DNREC to investigate the site through the Voluntary Clean-up Program. On February 4, 2008, the DNREC issued findings that no further action is required in relation to surface water and that a previously planned shoreline stabilization project would satisfactorily address shoreline erosion. The landfill itself will require a further Remedial Investigation and Feasibility Study to determine the type and scope of any additional work required. Until the Remedial Investigation and Feasibility Study is completed, the Company is unable to predict the impact of any required remediation. On May 29, 2008, the 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 the DNREC and other trustees to close out the assessment phase.

  South Central Region

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

Note 18 — Guarantees

     NRG and its subsidiaries enter into various contracts that include indemnification and guarantee provisions as a routine part of the Company’s business activities. Examples of these contracts include asset purchases and sale agreements, commodity sale and purchase agreements, retail contracts, joint venture agreements, EPC agreements, operation and maintenance agreements, service agreements, settlement agreements, and other types of contractual agreements with vendors and other third parties, as well as affiliates. These contracts generally indemnify the counterparty for tax, environmental liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. The Company is also obligated with respect to customer deposits associated with Reliant Energy. In some cases, NRG’s maximum potential liability cannot be estimated, since the underlying agreements contain no limits on potential liability.

     This Note 18 should be read in conjunction with the complete description under Note 26, Guarantees, to the Company’s financial statements in its Annual Report on Form 10-K for the year ended December 31, 2009.

34

Note 19 — Condensed Consolidating Financial Information

     As of March 31, 2010, the Company had outstanding $1.2 billion of 7.25% Senior Notes due 2014, $2.4 billion of 7.375% Senior Notes due 2016, $1.1 billion of 7.375% Senior Notes due 2017, and $700 million of 8.50% Senior Notes due 2019. The Senior Notes are guaranteed by certain of NRG’s current and future wholly-owned domestic subsidiaries, or guarantor subsidiaries.

     Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of March 31, 2010:

Arthur Kill Power LLC	NRG Generation Holdings, Inc.
Astoria Gas Turbine Power LLC	NRG Huntley Operations Inc.
Berrians I Gas Turbine Power LLC	NRG International LLC
Big Cajun II Unit 4 LLC	NRG Kaufman LLC
Cabrillo Power I LLC	NRG Mesquite LLC
Cabrillo Power II LLC	NRG MidAtlantic Affiliate Services Inc.
Chickahominy River Energy Corp.	NRG Middletown Operations Inc.
Commonwealth Atlantic Power LLC	NRG Montville Operations Inc.
Conemaugh Power LLC	NRG New Jersey Energy Sales LLC
Connecticut Jet Power LLC	NRG New Roads Holdings LLC
Devon Power LLC	NRG North Central Operations, Inc.
Dunkirk Power LLC	NRG Northeast Affiliate Services Inc.
Eastern Sierra Energy Company	NRG Norwalk Harbor Operations Inc.
El Segundo Power, LLC	NRG Operating Services Inc.
El Segundo Power II LLC	NRG Oswego Harbor Power Operations Inc.
GCP Funding Company LLC	NRG Power Marketing LLC
Hanover Energy Company	NRG Retail LLC
Huntley IGCC LLC	NRG Rocky Road LLC
Huntley Power LLC	NRG Saguaro Operations Inc.
Indian River IGCC LLC	NRG South Central Affiliate Services Inc.
Indian River Operations Inc.	NRG South Central Generating LLC
Indian River Power LLC	NRG South Central Operations Inc.
James River Power LLC	NRG South Texas LP
Kaufman Cogen LP	NRG Texas LLC
Keystone Power LLC	NRG Texas C & I Supply LLC
Lake Erie Properties Inc.	NRG Texas Holding Inc.
Langford Wind Power, LLC	NRG Texas Power LLC
Louisiana Generating LLC	NRG West Coast LLC
Middletown Power LLC	NRG Western Affiliate Services Inc.
Montville IGCC LLC	Oswego Harbor Power LLC
Montville Power LLC	Reliant Energy Power Supply, LLC
NEO Chester-Gen LLC	Reliant Energy Retail Holding, LLC
NEO Corporation	Reliant Energy Retail Services, LLC
NEO Freehold-Gen LLC	RE Retail Receivables, LLC
NEO Power Services Inc.	RERH Holdings, LLC
New Genco GP LLC	Reliant Energy Services Texas LLC
Norwalk Power LLC	Reliant Energy Texas Retail LLC
NRG Affiliate Services Inc.	Saguaro Power LLC
NRG Arthur Kill Operations Inc.	Somerset Operations Inc.
NRG Asia-Pacific Ltd.	Somerset Power LLC
NRG Astoria Gas Turbine Operations Inc.	Texas Genco Financing Corp.
NRG Bayou Cove LLC	Texas Genco GP, LLC
NRG Cabrillo Power Operations Inc.	Texas Genco Holdings, Inc.
NRG Cadillac Operations Inc.	Texas Genco LP, LLC
NRG California Peaker Operations LLC	Texas Genco Operating Services, LLC
NRG Cedar Bayou Development Company LLC	Texas Genco Services, LP
NRG Connecticut Affiliate Services Inc.	Vienna Operations, Inc.
NRG Construction LLC	Vienna Power LLC
NRG Devon Operations Inc.	WCP (Generation) Holdings LLC
NRG Dunkirk Operations, Inc.	West Coast Power LLC
NRG El Segundo Operations Inc.

35

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

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

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

36

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended March 31, 2010

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

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

37

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
March 31, 2010

				Non-
	Guarantor			Guarantor			NRG Energy, Inc.						Consolidated
(In millions)	Subsidiaries			Subsidiaries			(Note Issuer)			Eliminations (a)			Balance
ASSETS
Current Assets
Cash and cash equivalents	$	13		$	147		$	1,653		$	—		$	1,813
Funds deposited by counterparties		509			—			—			—			509
Restricted cash		1			6			—			—			7
Accounts receivable, net		664			36			—			—			700
Inventory		536			13			—			—			549
Derivative instruments valuation		2,724			—			—			—			2,724
Cash collateral paid in support of energy risk management activities		531			2			—			—			533
Prepayments and other current assets		153			65			177			(88	)		307
Total current assets		5,131			269			1,830			(88	)		7,142
Net property, plant and equipment		10,386			1,086			155			—			11,627
Other Assets
Investment in subsidiaries		693			312			18,564			(19,569	)		—
Equity investments in affiliates		42			379			—			—			421
Capital leases and notes receivable, less current portion		5,184			490			3,059			(8,257	)		476
Goodwill		1,713			—			—			—			1,713
Intangible assets, net		1,665			19			33			(31	)		1,686
Nuclear decommissioning trust fund		382			—			—			—			382
Derivative instruments valuation		964			—			11			—			975
Other non-current assets		37			9			110			—			156
Total other assets		10,680			1,209			21,777			(27,857	)		5,809
Total Assets	$	26,197		$	2,564		$	23,762		$	(27,945	)	$	24,578
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	58		$	120		$	32		$	(58	)	$	152
Accounts payable		(2,134	)		432			2,297			—			595
Derivative instruments valuation		2,287			2			65			—			2,354
Deferred income taxes		456			11			(293	)		—			174
Cash collateral received in support of energy risk management activities		509			—			—			—			509
Accrued expenses and other current liabilities		285			33			300			(30	)		588
Total current liabilities		1,461			598			2,401			(88	)		4,372
Other Liabilities
Long-term debt and capital leases		2,567			1,004			12,532			(8,257	)		7,846
Nuclear decommissioning reserve		304			—			—			—			304
Nuclear decommissioning trust liability		262			—			—			—			262
Deferred income taxes		1,857			(165	)		233			—			1,925
Derivative instruments valuation		396			29			14			—			439
Out-of-market contracts		301			7			—			(31	)		277
Other non-current liabilities		542			17			326			—			885
Total non-current liabilities		6,229			892			13,105			(8,288	)		11,938
Total liabilities		7,690			1,490			15,506			(8,376	)		16,310
3.625% Preferred Stock		—			—			247			—			247
Stockholders’ Equity		18,507			1,074			8,009			(19,569	)		8,021
Total Liabilities and Stockholders’ Equity	$	26,197		$	2,564		$	23,762		$	(27,945	)	$	24,578

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

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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2010

				Non-			NRG Energy,
	Guarantor			Guarantor			Inc.						Consolidated
(In millions)	Subsidiaries			Subsidiaries			(Note Issuer)			Eliminations (a)			Balance
Cash Flows from Operating Activities
Net income	$	189		$	12		$	58		$	(201	)	$	58
Adjustments to reconcile net income to net cash provided by operating activities:
Distributions and equity in (earnings)/losses of unconsolidated affiliates and consolidated subsidiaries		(7	)		(5	)		(194	)		201			(5	)
Depreciation and amortization		190			10			2			—			202
Provision for bad debts		9			—			—			—			9
Amortization of nuclear fuel		10			—			—			—			10
Amortization of financing costs and debt discount/premiums		—			2			6			—			8
Changes in deferred income taxes and liability for unrecognized tax benefits		111			2			(39	)		—			74
Changes in nuclear decommissioning liability		11			—			—			—			11
Changes in derivatives		22			2			—			—			24
Changes in collateral deposits supporting energy risk management activities		(172	)		—			—			—			(172	)
Loss/(gain) on sale of assets		2			—			(23	)		—			(21	)
Amortization of unearned equity compensation		—			—			6			—			6
Changes in option premiums collected		92			—			—			—			92
Cash (used)/provided by changes in other working capital		(199	)		(63	)		80			—			(182	)
Net Cash Provided/(Used) by Operating Activities		258			(40	)		(104	)		—			114
Cash Flows from Investing Activities
Intercompany (loans to)/receipts from subsidiaries		(178	)		—			(32	)		210			—
Investment in subsidiaries		—			328			(328	)		—			—
Capital expenditures		(99	)		(73	)		(13	)		—			(185	)
Increase in restricted cash, net		—			(5	)		—			—			(5	)
Decrease in notes receivable		—			7			—			—			7
Purchases of emission allowances		(34	)		—			—			—			(34	)
Proceeds from sale of emission allowances		9			—			—			—			9
Investments in nuclear decommissioning trust fund securities		(78	)		—			—			—			(78	)
Proceeds from sales of nuclear decommissioning trust fund securities		67			—			—			—			67
Proceeds from sale of assets		1			—			29			—			30
Other		—			—			(5	)		—			(5	)
Net Cash (Used)/Provided by Investing Activities		(312	)		257			(349	)		210			(194	)
Cash Flows from Financing Activities
Proceeds from intercompany loans		31			1			178			(210	)		—
Payment of dividends to preferred stockholders		—			—			(2	)		—			(2	)
Net receipt from acquired derivatives that include financing elements		13			—			—			—			13
Proceeds from issuance of long-term debt		3			7			—			—			10
Proceeds from issuance of common stock		—			—			2			—			2
Payment of deferred debt issuance costs		—			(2	)		—			—			(2	)
Payment of short and long-term debt		—			(193	)		(236	)		—			(429	)
Net Cash Provided/(Used) by Financing Activities		47			(187	)		(58	)		(210	)		(408	)
Effect of exchange rate changes on cash and cash equivalents		—			(3	)		—			—			(3	)
Net (Decrease)/Increase in Cash and Cash Equivalents		(7	)		27			(511	)		—			(491	)
Cash and Cash Equivalents at Beginning of Period		20			120			2,164			—			2,304
Cash and Cash Equivalents at End of Period	$	13		$	147		$	1,653		$	—		$	1,813

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

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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended March 31, 2009

							NRG Energy,
	Guarantor			Non-Guarantor			Inc.						Consolidated
(In millions)	Subsidiaries			Subsidiaries			(Note Issuer)			Eliminations (a)			Balance
Operating Revenues
Total operating revenues	$	1,566		$	95		$	—		$	(3	)	$	1,658
Operating Costs and Expenses
Cost of operations		698			68			3			(3	)		766
Depreciation and amortization		158			10			1			—			169
General and administrative		17			3			75			—			95
Development costs		2			2			9			—			13
Total operating costs and expenses		875			83			88			(3	)		1,043
Operating Income/(Loss)		691			12			(88	)		—			615
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries		21			—			397			(418	)		—
Equity in earnings of unconsolidated affiliates		1			21			—			—			22
Other income/(loss), net		1			(7	)		3			—			(3	)
Interest expense		(48	)		(21	)		(69	)		—			(138	)
Total other (expense )/income		(25	)		(7	)		331			(418	)		(119	)
Income/(Loss) Before Income Taxes		666			5			243			(418	)		496
Income tax expense		252			1			45			—			298
Net Income/(Loss) attributable to NRG Energy, Inc.	$	414		$	4		$	198		$	(418	)	$	198

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

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NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING BALANCE SHEETS
December 31, 2009

				Non-
	Guarantor			Guarantor			NRG Energy, Inc.						Consolidated
(In millions)	Subsidiaries			Subsidiaries			(Note Issuer)			Eliminations (a)			Balance
ASSETS
Current Assets
Cash and cash equivalents	$	20		$	120		$	2,164		$	—		$	2,304
Funds deposited by counterparties		177			—			—			—			177
Restricted cash		1			1			—			—			2
Accounts receivable-trade, net		837			39			—			—			876
Inventory		529			12			—			—			541
Derivative instruments valuation		1,636			—			—			—			1,636
Cash collateral paid in support of energy risk management activities		359			2			—			—			361
Prepayments and other current assets		194			61			157			(101	)		311
Total current assets		3,753			235			2,321			(101	)		6,208
Net Property, Plant and Equipment		10,494			1,009			61			—			11,564
Other Assets
Investment in subsidiaries		613			222			16,862			(17,697	)		—
Equity investments in affiliates		42			367			—			—			409
Capital leases and note receivable, less current portion		4,982			504			3,027			(8,009	)		504
Goodwill		1,718			—			—			—			1,718
Intangible assets, net		1,755			20			33			(31	)		1,777
Nuclear decommissioning trust fund		367			—			—			—			367
Derivative instruments valuation		718			—			8			(43	)		683
Other non-current assets		29			8			111			—			148
Total other assets		10,224			1,121			20,041			(25,780	)		5,606
Total Assets	$	24,471		$	2,365		$	22,423		$	(25,881	)	$	23,378
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	58		$	310		$	261		$	(58	)	$	571
Accounts payable		(852	)		393			1,156			—			697
Derivative instruments valuation		1,469			2			2			—			1,473
Deferred income taxes		456			11			(270	)		—			197
Cash collateral received in support of energy risk management activities		177			—			—			—			177
Accrued expenses and other current liabilities		261			82			347			(43	)		647
Total current liabilities		1,569			798			1,496			(101	)		3,762
Other Liabilities
Long-term debt and capital leases		2,533			1,003			12,320			(8,009	)		7,847
Nuclear decommissioning reserve		300			—			—			—			300
Nuclear decommissioning trust liability		255			—			—			—			255
Deferred income taxes		1,711			(165	)		237			—			1,783
Derivative instruments valuation		323			28			79			(43	)		387
Out-of-market contracts		318			7			—			(31	)		294
Other non-current liabilities		431			16			359			—			806
Total non-current liabilities		5,871			889			12,995			(8,083	)		11,672
Total liabilities		7,440			1,687			14,491			(8,184	)		15,434
3.625% Preferred Stock		—			—			247			—			247
Stockholders’ Equity		17,031			678			7,685			(17,697	)		7,697
Total Liabilities and Stockholders’ Equity	$	24,471		$	2,365		$	22,423		$	(25,881	)	$	23,378

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

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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2009

				Non-			NRG Energy,
	Guarantor			Guarantor			Inc.						Consolidated
(In millions)	Subsidiaries			Subsidiaries			(Note Issuer)			Eliminations (a)			Balance
Cash Flows from Operating Activities
Net income	$	414		$	4		$	198		$	(418	)	$	198
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in (earnings)/losses of unconsolidated affiliates and consolidated subsidiaries		(22	)		(21	)		(397	)		418			(22	)
Depreciation and amortization		158			10			1			—			169
Amortization of nuclear fuel		10			—			—			—			10
Amortization of financing costs and debt discount/premiums		—			3			6			—			9
Amortization of intangibles and out-of-market contracts		(34	)		—			—			—			(34	)
Changes in deferred income taxes and liability for unrecognized tax benefits		116			(11	)		194			—			299
Changes in nuclear decommissioning liability		6			—			—			—			6
Changes in derivatives		(301	)		(3	)		—			—			(304	)
Changes in collateral deposits supporting energy risk management activities		312			—			—			—			312
Gain on sale of assets		(1	)		—			—			—			(1	)
Gain on sale of emission allowances		(7	)		—			—			—			(7	)
Amortization of unearned equity compensation		—			—			7			—			7
Changes in option premium collected		(270	)		—			—			—			(270	)
Cash (used)/provided by changes in other working capital		(161	)		38			(110	)		—			(233	)
Net Cash Provided/(Used) by Operating Activities		220			20			(101	)		—			139
Cash Flows from Investing Activities
Intercompany (loans to)/receipts from subsidiaries		(231	)		—			(201	)		432			—
Investment in subsidiaries		—			—			(60	)		60			—
Capital expenditures		(165	)		(68	)		—			—			(233	)
Decrease/(increase) in restricted cash, net		4			(5	)		—			—			(1	)
Decrease/(increase) in notes receivable		—			11			(8	)		—			3
Purchases of emission allowances		(35	)		—			—			—			(35	)
Proceeds from sale of emission allowances		8			—			—			—			8
Investment in nuclear decommissioning trust fund securities		(83	)		—			—			—			(83	)
Proceeds from sales of nuclear decommissioning trust fund securities		78			—			—			—			78
Proceeds from sale of assets		4			—			—			—			4
Net Cash Used by Investing Activities		(420	)		(62	)		(269	)		492			(259	)
Cash Flows from Financing Activities
(Payments)/proceeds from intercompany loans		164			30			238			(432	)		—
Intercompany investments		—			60			—			(60	)		—
Payment of dividends to preferred stockholders		—			—			(14	)		—			(14	)
Receipt from acquired derivatives that include financing elements		40			—			—			—			40
Payment of deferred debt issuance costs		—			(1	)		—			—			(1	)
Payment of short and long-term debt		—			(4	)		(205	)		—			(209	)
Net Cash Provided by Financing Activities		204			85			19			(492	)		(184	)
Effect of exchange rate changes on cash and cash equivalents		—			(2	)		—			—			(2	)
Net Increase/(Decrease) in Cash and Cash Equivalent		4			41			(351	)		—			(306	)
Cash and Cash Equivalents at Beginning of Period		(2	)		159			1,337			—			1,494
Cash and Cash Equivalents at End of Period	$	2		$	200		$	986		$	—		$	1,188

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

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Note 20 — Subsequent Event

     On May 10, 2010, NINA and TEPCO Nuclear Energy America LLC, or TNEA, a wholly-owned subsidiary of The Tokyo Electric Power Company of Japan, Inc., or TEPCO, signed an Investment and Option Agreement whereby TNEA agreed to acquire up to a 20% interest in NINA Investments Holdings LLC, or Holdings. Holdings is a wholly-owned subsidiary of NINA, which indirectly holds NINA’s ownership interest in the STP Units 3 and 4 Project. TNEA will initially invest $155 million for a 10% share of Holdings, which includes a $30 million option premium payment to Holdings. This option, which expires approximately one year from the date of signing the Investment and Option Agreement, will enable TNEA to buy an additional 10% of Holdings for another payment of $125 million. The closing is contingent upon NINA’s receipt of a U.S. DOE loan guarantee commitment. Upon its initial investment, TNEA will hold a 9.2375% interest in the STP Units 3 and 4 Project, bringing NINA’s investment down to 83.1375%. If TNEA exercises its option to increase its ownership of Holdings by an additional 10%, it will own 18.475% of the STP Units 3 and 4 Project, bringing NINA’s investment down to 73.90%.

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

     In this discussion and analysis, NRG discusses and explains its financial condition and results of operations, including:

• Factors which affect NRG’s business;

• NRG’s earnings and costs in the periods presented;

• Changes in earnings and costs between periods;

• Impact of these factors on NRG’s overall financial condition;

• A discussion of new and ongoing initiatives that may affect NRG’s future results of operations and financial condition;

• Expected future expenditures for capital projects; and

• Expected sources of cash for future operations and capital expenditures.

     As you read this discussion and analysis, refer to the Company’s Condensed Consolidated Statements of Operations to this Form 10-Q, which present the results of operations for the three months ended March 31, 2010, and 2009. The Company analyzes and explains the differences between periods in the specific line items of NRG’s Condensed Consolidated Statements of Operations. Also refer to NRG’s Annual Report on Form 10-K for the year ended December 31, 2009, which includes detailed discussions of various items impacting the Company’s business, results of operations and financial condition, including:

• Introduction and Overview section which provides a description of NRG’s business segments;

• Strategy section;

• Business Environment section, including how regulation, weather, and other factors affect NRG’s business; and

• Critical Accounting Policies and Estimates section.

     The discussion and analysis below has been organized as follows:

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

• Results of operations beginning with an overview of the Company’s consolidated results, followed by a more detailed discussion of those results by operating segment;

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

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Executive Summary

 Introduction and Overview

     NRG Energy, Inc., or NRG or the Company, is primarily a wholesale power generation company with a significant presence in major competitive power markets in the U.S., as well as a major retail electricity provider in the ERCOT (Texas) market through Reliant Energy. NRG is engaged in the ownership, development, construction and operation of power generation facilities, the transacting in and trading of fuel and transportation services, the trading of energy, capacity and related products in the U.S. and select international markets, and the supply of electricity and energy services to retail electricity customers in the Texas market.

     As of March 31, 2010, NRG had a total global generation portfolio of 186 active operating fossil fuel and nuclear generation units, at 44 power generation plants, with an aggregate generation capacity of approximately 24,005 MW, and approximately 400 MW under construction which includes partner interests of 200 MW. In addition to its fossil fuel plant ownership, NRG has ownership interests in operating renewable facilities with an aggregate generation capacity of 365 MW, consisting of three wind farms representing an aggregate generation capacity of 345 MW (which includes partner interest of 75 MW) and a solar facility with an aggregate generation capacity of 20 MW. Within the U.S., NRG has large and diversified power generation portfolios in terms of geography, fuel-type and dispatch levels, with approximately 23,000 MW of fossil fuel and nuclear generation capacity in 178 active generating units at 42 plants. The Company’s power generation facilities are most heavily concentrated in Texas (approximately 11,340 MW, including 345 MW from three wind farms), the Northeast (approximately 6,905 MW), South Central (approximately 2,855 MW), and West (approximately 2,150 MW, including 20 MW from a solar facility) regions of the U.S., with approximately 115 MW of additional generation capacity from the Company’s thermal assets. In addition, through certain foreign subsidiaries, NRG has investments in power generation projects located in Australia and Germany with approximately 1,005 MW of generation capacity.

     NRG’s principal domestic power plants consist of a mix of natural gas-, coal-, oil-fired, nuclear and renewable facilities, representing approximately 45%, 32%, 16%, 5% and 2% of the Company’s total domestic generation capacity, respectively. In addition, 9% of NRG’s domestic generating facilities have dual or multiple fuel capacity, which allows plants to dispatch with the lowest cost fuel option.

     NRG’s domestic generation facilities consist of intermittent, baseload, intermediate and peaking power generation facilities, the ranking of which is referred to as the Merit Order, and include thermal energy production plants. The sale of capacity and power from baseload generation facilities accounts for the majority of the Company’s revenues and provides a stable source of cash flow. In addition, NRG’s generation portfolio provides the Company with opportunities to capture additional revenues by selling power during periods of peak demand, offering capacity or similar products to retail electric providers and others, and providing ancillary services to support system reliability.

     Reliant Energy, the Company’s retail electricity provider, arranges for the transmission and delivery of electricity to customers, bills customers, collects payments for electricity sold and maintains call centers to provide customer service. Based on metered locations, as of March 31, 2010, Reliant Energy had approximately 1.5 million Mass customers and approximately 0.1 million C&I customers, with expected annual volumes for these customer classes of 20 TWhs and 30 TWhs, respectively.

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

  NRG’s Business Strategy

     NRG’s business strategy is intended to maximize shareholder value through the production and sale of safe, reliable and affordable power to its customers in the markets served by the Company, while aggressively positioning the Company to meet the market’s increasing demand for sustainable and low carbon energy solutions. The Company believes that success in providing energy solutions that address sustainability and climate change concerns will not only reduce the carbon and capital intensity of the Company in the future, it also will reduce the real and perceived linkage between the Company’s financial performance and prospects, and volatile commodity prices, particularly with respect to natural gas. The Company’s strategy is focused on: (i) top decile operating performance of its existing operating assets and enhanced operating performance of the Company’s commercial operations and hedging program; (ii) repowering of power generation assets at existing sites and development of new power generation projects; (iii) empowering new and current retail customers with distinctive products and services that transform how they use, manage and value energy; (iv) engaging in a proactive capital allocation plan focused on achieving the regular return of capital to stockholders within the

45

dictates of prudent balance sheet management; and (v) pursuit of selective acquisitions, joint ventures, divestitures and investments in energy-related new businesses and new technologies in order to enhance the Company’s asset mix and competitive position in its core markets, both with respect to its traditional core business and opportunities associated with the new energy economy. This strategy is supported by the Company’s five major initiatives (FORNRG, RepoweringNRG, econrg, Future NRG and NRG Global Giving) which are designed to enhance the Company’s competitive advantages in these strategic areas and enable the Company to convert the challenges faced by the power industry in the coming years into opportunities for financial growth. This strategy is being implemented by focusing on the following principles, which are more fully described in the Company’s 2009 Annual Report on Form 10-K.

     Operational Performance — The Company is focused on increasing value from its existing assets, primarily through the Company’s FORNRG 2.0 initiative, commercial operations strategy, achieving synergies between the Company’s retail and wholesale business in Texas, and maintaining of appropriate levels of liquidity, debt and equity in order to ensure continued access to capital through all economic and financial cycles.

     Development — NRG is favorably positioned to pursue growth opportunities through expansion of its existing generating capacity and development of new generating capacity at its existing facilities, primarily through the Company’s RepoweringNRG and econrg initiatives. NRG expects that these efforts will provide some or all of the following benefits: improved heat rates; lower delivered costs; expanded electricity production capability; improved ability to dispatch economically across the regional general portfolio; increased technological and fuel diversity; and reduced environmental impacts, including facilities that either have near zero GHG emissions or can be equipped to capture and sequester GHG emissions. In addition, several of the Company’s original RepoweringNRG projects or projects commenced under that initiative since its inception may qualify for financial support under the infrastructure financing component of the American Recovery and Reinvestment Act as well as other government incentive packages. NRG has several applications pending or contemplated.

     New Businesses and New Technology — NRG is focused on the development of and investment in energy-related new businesses and new technologies, including low or no GHG emitting energy generating sources, such as nuclear, wind, solar thermal, photovoltaic, biomass, as well as other endeavors where the benefits of such investments represent significant commercial opportunities and create a comparative advantage for the Company, such as smart meters, electric vehicle ecosystems, and distributed “clean” solutions. Furthermore, the Company, supported by the econrg initiative, intends to capitalize on the high growth opportunities presented by government-mandated renewable portfolio standards, tax incentives and loan guarantees for renewable energy projects, new technologies and expected future carbon regulation.

     Company-Wide Initiatives — In addition, the Company’s overall strategy is also supported by Future NRG and NRG Global Giving initiatives, which address workforce planning and community involvement and support, respectively.

     Finally, NRG will continue to pursue selective acquisitions, joint ventures and divestitures to enhance its asset mix and competitive position in the Company’s core markets. NRG intends to concentrate on opportunities that present attractive risk-adjusted returns. NRG will also opportunistically pursue other strategic transactions, including mergers, acquisitions or divestitures.

Environmental Matters

 Climate Change

     In 2009, in the course of producing approximately 71 million MWh of electricity, NRG’s power plants emitted 59 million tonnes of CO₂, of which 53 million tonnes were emitted in the U.S., 3 million tonnes in Germany and 3 million tonnes in Australia. During the same period, NRG emitted approximately 8 million tons of CO₂ in the RGGI region. The impact from legislation or federal, regional or state regulation of GHGs on the Company’s financial performance will depend on a number of factors, including the overall level of GHG reductions required under any such regulations, the price and availability of offsets, and the extent to which NRG would be entitled to receive CO₂ emissions allowances without having to purchase them in an auction or on the open market. Thereafter, under any such legislation or regulation, the impact on NRG would depend on the Company’s level of success in developing and deploying low and no carbon technologies such as those being pursued as discussed in the above.

     Congress was unable to come to an agreement on climate legislation in 2009 and the subject continues to be a topic for consideration in 2010. Lack of legislation will prolong the uncertainty of the nature and timing of GHG requirements and their resulting impact on NRG.

46

     The U.S. EPA issued a rule addressing tailpipe limitations for light duty vehicles and a final interpretation of the Johnson Memorandum addressing when a compound becomes a regulated pollutant. The combined impact of these two actions is that power plants and other stationary sources that emit GHGs will be subject to NSR/PSD and Title V permitting requirements in 2011. The immediate impact to NRG’s new and modified facilities is not expected to be material; the Company will continue to evaluate the potential long-term impact as regulatory programs are implemented over time.

Environmental Regulatory Landscape

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

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

     On May 4, 2010, the California State Water Resources Control Board adopted a statewide 316(b) policy to mitigate once through cooling in California. Options for power plants with once through cooling include transitioning to a closed loop system, retirement or submitting an alternative plan that meets equivalent mitigation criteria. Specified compliance dates for NRG’s El Segundo and Encina Power Plants are December 31, 2015 and December 31, 2017, respectively. NRG is analyzing compliance through a mix of alternative mitigation plans and repowering.

Regulatory Matters

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

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

     California — On May 4, 2010, the Court of Appeals for the District of Columbia Circuit in Southern California Edison Company v. FERC vacated FERC’s acceptance of station power rules for the CAISO market, and remanded the case for further proceedings at FERC. As a result of the court’s decision, NRG’s power plants may be prevented from netting their station power consumption against their sales on a monthly basis in the California markets, which could require NRG to purchase station power at retail rates. Additionally, the precedent announced in this case may affect station power tariffs in other markets.

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 NRG Energy, Inc. for the three months ended March 31, 2010, and 2009:

	Three months ended March 31,
(In millions except otherwise noted)	2010			2009			Change %
Operating Revenues
Energy revenue	$	678		$	887			(24	)%
Capacity revenue		211			260			(19	)
Retail revenue		1,245			—			—
Risk management activities		91			437			(79	)
Contract amortization		(62	)		21			(395	)
Thermal revenue		28			34			(18	)
Other revenues		24			19			26
Total operating revenues		2,215			1,658			34
Operating Costs and Expenses
Cost of sales		1,188			453			162
Risk management activities		136			68			100
Other cost of operations		315			245			29
Total cost of operations		1,639			766			114
Depreciation and amortization		202			169			20
Selling, general and administrative		130			95			37
Development costs		9			13			(31	)
Total operating costs and expenses		1,980			1,043			90
Gain on sale of assets		23			—			—
Operating income		258			615			(58	)
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates		14			22			(36	)
Other income/(loss), net		4			(3	)		(233	)
Interest expense		(153	)		(138	)		11
Total other expenses		(135	)		(119	)		13
Income before income tax expense		123			496			(75	)
Income tax expense		65			298			(78	)
Net Income attributable to NRG Energy, Inc.	$	58		$	198			(71	)
Business Metrics
Average natural gas price — Henry Hub ($/MMbtu)		5.30			4.58			16	%

48

The table below represents the results of NRG excluding the impact of Reliant Energy during the three months ended March 31, 2010 compared to the same period in 2009:

	Three months ended March 31,
	2010									2009
							Total excluding
(In millions)	Consolidated			Reliant Energy			Reliant Energy			Consolidated		Change %
Operating Revenues
Energy revenue	$	678		$	—		$	678		$	887		(24	)%
Capacity revenue		211			—			211			260		(19	)
Retail revenue		1,245			1,245			—			—		—
Risk management activities		91			—			91			437		(79	)
Contract amortization		(62	)		(69	)		7			21		(67	)
Thermal revenue		28			—			28			34		(18	)
Other revenues		24			—			24			19		26
Total operating revenues		2,215			1,176			1,039			1,658		(37	)
Operating Costs and Expenses
Cost of sales		1,188			907			281			453		(38	)
Risk management activities		136			323			(187	)		68		(375	)
Other operating costs		315			45			270			245		10
Total cost of operations		1,639			1,275			364			766		(52	)
Depreciation and amortization		202			30			172			169		2
Selling, general and administrative		130			58			72			95		(24	)
Development costs		9			—			9			13		(31	)
Total operating costs and expenses		1,980			1,363			617			1,043		(41	)
Gain on sale of assets		23			—			23			—		—
Operating Income	$	258		$	(187	)	$	445		$	615		(28	)%

  Operating Revenues

     Operating revenues, excluding risk management activities, increased by $903 million during the three months ended March 31, 2010, compared to the same period in 2009.

• Retail revenue — Reliant Energy contributed $1.2 billion of retail revenue during the three months ended March 31, 2010. Retail revenue includes Mass revenues of $713 million, C&I revenues of $489 million, and supply management revenues of $43 million.

• Energy revenue — decreased $209 million during the three months ended March 31, 2010, compared to the same period in 2009:

o Texas — increased by $34 million, with $21 million of the increase driven by an increase in generation and $14 million of the increase driven by higher energy prices. The average realized energy price increased by 2%, driven by an 8% decrease in merchant prices offset by a 3% increase in contract prices. Generation increased 4%, driven by a 1% increase in coal plant generation, a 94% increase in gas plant generation, a 97% increase in wind farm generation, offset by an 8% decrease in nuclear plant generation. Gas plant generation was supported by the recently constructed Cedar Bayou 4 gas plant which began commercial operations in June 2009 and wind farm generation increased due to the Langford wind farm, which began commercial operations in December 2009. Coal plant generation was supported by reduced planned maintenance hours in 2010. Nuclear plant generation decreased due to an outage.

o Northeast — decreased by $60 million, with $34 million driven by lower energy prices and $23 million attributable to a reduction in generation. Average merchant energy prices were lower by 25%. Generation decreased by 9% with a 3% decrease in coal generation and a 72% decrease in oil and gas generation. Weakened demand for power resulted in reduced merchant energy prices.

o South Central — increased by $10 million due to an increase in contract revenues. Total MWh sales to the region’s contract customers were up 9% while the average realized price on contract energy sales was $26.17 per MWh in 2010 compared to $23.37 per MWh in 2009. Megawatt hours sold to the merchant market decreased by 20% while prices rose by 20%.

o Intercompany energy revenue — intercompany sales of $200 million by the Company’s Texas region to Reliant Energy were eliminated in consolidation.

49

• Capacity revenue — decreased $49 million during the three months ended March 31, 2010, compared to the same period in 2009:

o Texas — decreased by $40 million due to a lower proportion of baseload contracts which contained a capacity component.

o Northeast — increased by $8 million due to higher capacity prices in the NYISO.

o South Central — decreased by $11 million primarily due to contract expirations.

o Intercompany capacity revenue — intercompany sales of $4 million by the Company’s Texas region to Reliant Energy were eliminated in consolidation.

• Contract amortization revenue — decreased by $83 million in the three months ended March 31, 2010, as compared to the same period in 2009. The decrease includes $69 million of amortization for net in-market C&I contracts related to the Reliant Energy acquisition in May 2009 and a reduction of $13 million in revenue from the Texas Genco acquisition due to the lower volume of contracted energy.

• Other revenues — increased by $5 million driven by $4 million in higher ancillary revenue and $8 million in higher fuels trading. These increases were offset by $7 million in lower emissions credit revenue. Intercompany ancillary revenue of $12 million by the Company’s Texas region to Reliant Energy was eliminated in consolidation.

  Cost of Operations

     Cost of operations, excluding risk management activities, increased $805 million during the three months ended March 31, 2010, compared to the same period in 2009.

• Cost of sales — increased $735 million during the three months ended March 31, 2010, compared to the same period in 2009 due to:

o Retail — Reliant Energy incurred $907 million of cost of energy during the three months ended March 31, 2010. Supply costs were $617 million, including $216 million of intercompany supply costs. Transmission and distribution charges totaled $300 million for the period. These costs were offset by $10 million of contract amortization for net out-of-market supply contracts related to the Reliant Energy acquisition in May 2009.

o Texas — cost of energy increased $71 million due to higher natural gas and coal costs. Natural gas costs increased $24 million, consisting of $3 million reflecting a 26% increase in average natural gas prices and $21 million reflecting a 94% increase in gas-fired generation. Coal costs increased $17 million due to higher coal prices and increased transportation costs. In addition, cost of energy increased due to a $12 million increase in ancillary service costs and an $18 million increase in purchased energy and other fuel costs.

o Northeast — cost of energy decreased $24 million due to a $17 million reduction in natural gas and oil costs and a $6 million reduction in coal costs. Natural gas and oil costs decreased due to 72% percent lower generation offset by 8% higher average natural gas prices. The coal costs decreased due to lower prices.

o South Central — cost of energy increased $6 million due to an increase in purchased energy reflecting higher fuel costs associated with energy from the region’s tolled facility.

• Other cost of operations — increased $70 million during the three months ended March 31, 2010, compared to the same period in 2009. Reliant Energy incurred $29 million related to customer service operations and $16 million in gross receipts tax on revenue. Other costs of operations increased by $16 million in the Company’s Texas region due to $14 million in major maintenance at its various plants. In addition, the Company’s Northeast region incurred a $14 million charge relating to the write-off of previously capitalized costs on the Indian River Unit 3 back-end controls project together with associated cancellation penalties, partially offset by a $9 million decrease in maintenance expenses.

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  Risk Management Activities

     Risk management activities include economic hedges that did not qualify for cash flow hedge accounting, ineffectiveness on cash flow hedges, and trading activities. Total derivative gains decreased by $413 million during the three months ended March 31, 2010, compared to the same period in 2009. The breakdown of changes by region follows:

	Three Months ended March 31, 2010
	Reliant							South
	Energy			Texas		Northeast		Central			West		Thermal			Elimination		Total
	(In millions)
Net gains/(losses) on settled positions	$	(35	)	$	8	$	33	$	(13	)	$	—	$	1		$	—	$	(6	)
Mark-to-market gains/(losses)		(288	)		227		25		(2	)		1		(1	)		—		(38	)
Total derivative gains/(losses) included in revenues and cost of operations	$	(323	)	$	235	$	58	$	(15	)	$	1	$	—		$	—	$	(44	)

	Three Months ended March 31, 2009
					South
	Texas		Northeast		Central			West			Thermal		Elimination		Total
	(In millions)
Net gains/(losses) on settled positions	$	29	$	56	$	10		$	(2	)	$	1	$	—	$	94
Mark-to-market gains/(losses)		169		131		(25	)		(1	)		1		—		275
Total derivative gains/(losses) included in revenues and cost of operations	$	198	$	187	$	(15	)	$	(3	)	$	2	$	—	$	369

     The breakdown of gains and losses included in revenue and cost of operations by region are as follows:

	Three months ended March 31, 2010
	Reliant								South
	Energy		Texas			Northeast			Central			West		Thermal			Elimination (a)			Total
	(In millions)
Net gains/(losses) on settled positions, or financial income in revenues	$	—	$	9		$	33		$	(12	)	$	—	$	1		$	(9	)	$	22
Mark-to-market results in revenues
Reversal of previously recognized unrealized gains on settled positions related to economic hedges		—		(37	)		(24	)		—			—		(1	)		(11	)		(73	)
Reversal of previously recognized unrealized losses on settled positions related to trading activity		—		13			3			2			—		—			—			18
Net unrealized gains/(losses) on open positions related to economic hedges		—		222			30			(18	)		—		—			(124	)		110
Net unrealized gains on open positions related to trading activity		—		5			5			3			1		—			—			14
Subtotal mark-to-market results		—		203			14			(13	)		1		(1	)		(135	)		69
Total derivative gains/(losses) included in revenues	$	—	$	212		$	47		$	(25	)	$	1	$	—		$	(144	)	$	91

(a) Represents the elimination of $144 million intercompany gain on Texas region. The offsetting intercompany loss is included in cost of operations in Reliant Energy region.

51

	Three months ended March 31, 2009
							South
	Texas			Northeast			Central			West			Thermal			Elimination		Total
	(In millions)
Net gains/(losses) on settled positions, or financial income in revenues	$	38		$	60		$	13		$	(2	)	$	1		$	—	$	110
Mark-to-market results in revenues
Reversal of previously recognized unrealized gains on settled positions related to economic hedges		(21	)		(31	)		—			—			(1	)		—		(53	)
Reversal of previously recognized unrealized gains on settled positions related to trading activity		(29	)		(14	)		(26	)		—			—			—		(69	)
Net unrealized gains/(losses) on open positions related to economic hedges		273			168			—			(1	)		2					442
Net unrealized gains/(losses) on open positions related to trading activity		2			(1	)		6			—			—			—		7
Subtotal mark-to-market results		225			122			(20	)		(1	)		1			—		327
Total derivative gains/(losses) included in revenues	$	263		$	182		$	(7	)	$	(3	)	$	2		$	—	$	437

	Three months ended March 31, 2010
	Reliant								South
	Energy			Texas			Northeast		Central			Elimination (a)		Total
	(In millions)
Net gains/(losses) on settled positions, or financial expense in cost of operations	$	(35	)	$	(1	)	$	—	$	(1	)	$	9	$	(28	)
Mark-to-market results in cost of operations
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges		(3	)		15			5		5			11		33
Reversal of loss positions acquired as part of the Reliant Energy acquisition as of May 1, 2009		90			—			—		—			—		90
Net unrealized gains/(losses) on open positions related to economic hedges		(375	)		9			6		6			124		(230	)
Subtotal mark-to-market results		(288	)		24			11		11			135		(107	)
Total derivative gains/(losses) included in cost of operations	$	(323	)	$	23		$	11	$	10		$	144	$	(135	)

(a) Represents the elimination of $144 million intercompany loss in the Reliant Energy region. The offsetting intercompany gain is included in revenue in the Texas region.

	Three months ended March 31, 2009
							South
	Texas			Northeast			Central			Elimination		Total
	(In millions)
Net losses on settled positions, or financial expense in cost of operations	$	(9	)	$	(4	)	$	(3	)	$	—	$	(16	)
Mark-to-market results in cost of operations
Reversal of previously recognized unrealized losses on settled positions related to economic hedges		13			24			—			—		37
Net unrealized losses on open positions related to economic hedges		(69	)		(15	)		(5	)		—		(89	)
Subtotal mark-to-market results		(56	)		9			(5	)		—		(52	)
Total derivative gains/(losses) included in cost of operations	$	(65	)	$	5		$	(8	)	$	—	$	(68	)

     For the period ended March 31, 2010, the $110 million gain in revenue from economic hedge positions is primarily driven by an increase in value of forward sales of natural gas and electricity due to a decrease in forward power and gas prices. The $230 million loss in cost of energy from economic hedge positions is primarily driven by a decrease in value of forward purchases of natural gas, electricity and fuel due to a decrease in forward power and gas prices. Reliant Energy’s $90 million gain from the roll-off of acquired derivatives consists of loss positions that were acquired as of May 1, 2009, and valued using forward prices on that date. The roll-off amounts were offset by realized losses at the settled prices and higher costs of physical power which are reflected in revenues and cost of operations during the same period.

52

     For the period ended March 31, 2009, the $442 million mark-to-market gain in revenue related to economic hedges consisted of a $217 million gain recognized in earnings from previously deferred amounts in accumulated OCI as the Company discontinued cash flow hedge accounting in the first quarter for certain 2009 transactions in Texas and New York due to lower expected generation, combined with a $225 million increase in value in forward sales of electricity and fuel relating to economic hedges due to lower forward power and gas prices. The $52 million mark-to-market loss in expense related to economic hedges consisted of a $23 million decrease in value of forward purchases of fuel and a loss of $29 million resulting from discontinued NPNS designated coal purchases due to expected lower coal consumption. Accordingly, the Company could not take physical delivery of coal purchase transactions under NPNS designation.

     In accordance with ASC 815-10-45-9, the following table represents the results of the Company’s financial and physical trading of energy commodities for the three months ended March 31, 2010, and 2009. The realized financial trading results and unrealized financial and physical trading results are included in the risk management activities above, while the realized physical trading results are included in energy revenue. The Company’s trading activities are subject to limits within the Company’s Risk Management Policy.

	Three months
	ended March 31,
(In millions)	2010			2009
Trading gains/(losses)
Realized	$	(11	)	$	70
Unrealized		32			(62	)
Total trading gains/(losses)	$	21		$	8

  Depreciation and Amortization

     NRG’s depreciation and amortization expense increased by $33 million for the three months ended March 31, 2010, compared to the same period in 2009. Reliant Energy’s depreciation and amortization expense for the three month period was $30 million principally for amortization of customer relationships. The balance of the increase was due to depreciation on the baghouse projects in western New York, the Cedar Bayou 4 project which began commercial operations in June 2009 and the Langford wind farm project which began commercial operations in December 2009.

  Selling, General and Administrative Expenses

     Selling, general and administrative expenses increased by $35 million for the three months ended March 31, 2010, compared to the same period in 2009. The increase was due to:

• Retail selling, general and administrative expense — totaled $58 million, including $9 million of bad debt expense incurred during the three months ended March 31, 2010.

This increase was offset by:

• Consultant costs — decreased due to non-recurring costs related to Exelon’s exchange offer and proxy contest efforts of $5 million and Reliant Energy acquisition and integration costs of $12 million incurred in 2009.

  Gain on Sale of Assets

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

  Equity in Earnings of Unconsolidated Affiliates

     NRG’s equity earnings from unconsolidated affiliates decreased by $8 million for the three months ended March 31, 2010, compared to the same period in 2009. For the three months ended March 31, 2009, NRG recognized $12 million of equity earnings from its investment in MIBRAG, which was sold in June 2009. This was partially offset by a $6 million increase in equity earnings from its Sherbino I Wind Farm LLC investment for the three months ended March 31, 2010.

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  Other Income/(Loss), Net

     NRG’s other income/(loss), net increased $7 million for the three months ended March 31, 2010, compared to the same period in 2009. The 2009 amount includes a $9 million mark-to-market unrealized loss on a forward contract for foreign currency executed to hedge the MIBRAG sale proceeds. Interest income for 2010 was higher compared to 2009 due to increased interest rates.

  Interest Expense

     NRG’s interest expense increased $15 million for the three months ended March 31, 2010, compared to the same period in 2009. This increase was due to $15 million related to the issuance of the 2019 Senior Notes in June 2009, and $8 million related to a reduction in capitalized interest expense compared to the same period in 2009 due to a lower volume of capital projects. These increases were offset by a $7 million decrease due to the settlement of the CSF Debt in 2009 and early 2010, and a $3 million decrease due to a lower outstanding principal balance on the Company’s Term Loan Facility and lower interest rates related to the unhedged portion of the Term Loan.

  Income Tax Expense

     NRG’s income tax expense decreased by $233 million for the three months ended March 31, 2010, compared to the same period in 2009. The decrease in income tax expense was primarily due to a decrease in income. The effective tax rate was 52.7% and 60.0% for the three months ended March 31, 2010, and 2009, respectively.

     For the three months ended March 31, 2010, NRG’s overall effective tax rate was different than the statutory rate of 35% primarily due to state and local income taxes as well as recording federal and state tax expense and interest for unrecognized tax benefits. For the three months ended March 31, 2009, NRG’s effective tax rate was increased primarily due to the impact of state and local income taxes in addition to an increase in valuation allowance as a result of capital losses generated in the quarter for which there were no projected capital gains or available tax planning strategies.

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Results of Operations — Regional Discussions

     The following is a detailed discussion of the results of operations of NRG’s retail business segment.

  Reliant Energy

     For a discussion of the business profile of the Company’s Reliant Energy operations, see pages 94-96 of NRG Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2009.

  Selected Income Statement Data

	Three months ended
(In millions, except otherwise noted)	March 31, 2010
Operating Revenues
Mass revenues	$	713
Commercial and Industrial revenues		489
Supply management revenues		43
Contract amortization		(69	)
Total operating revenues		1,176
Operating Costs and Expenses
Cost of energy (including risk management activities)		1,230
Other operating expenses		103
Depreciation and amortization		30
Operating Loss	$	(187	)
Electricity sales volume — GWh (in thousands):
Mass		4,814
Commercial and Industrial (a)		6,209
Business Metrics
Weighted average retail customers count (in thousands, metered locations)
Mass		1,521
Commercial and Industrial (a)		64
Retail customers count (in thousands, metered locations)
Mass		1,520
Commercial and Industrial (a)		64
Cooling Degree Days, or CDDs (b)		17
CDD’s 30-year average		82
Heating Degree Days, or HDDs (b)		1,242
HDD’s 30-year average		950

(a)

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

(b)

National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An 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. The CDDs/HDDs amounts are representative of the Coast and North Central Zones within the ERCOT market in which Reliant Energy serves its customer base.

55

  Operating Income

     Operating loss for the three months ended March 31, 2010, was $187 million, which consisted of the following:

	Three months ended
(In millions, except otherwise noted)	March 31, 2010
Reliant Energy Operating Loss:
Mass revenues	$	713
Commercial and Industrial revenues		489
Supply management revenues		43
Total retail operating revenues (a)		1,245
Retail cost of sales (a)		952
Total retail gross margin		293
Unrealized losses on energy supply derivatives		(288	)
Contract amortization, net		(59	)
Other operating expenses		(103	)
Depreciation and amortization		(30	)
Operating Loss	$	(187	)

(a) Amounts exclude unrealized gains/(losses) on energy supply derivatives and contract amortization.

• Gross margin — Reliant Energy’s gross margin totaled $293 million for the quarter. Volumes were higher due to greater customer usage as a result of cooler weather as compared to the 30-year HDD average. Customer counts declined 1% during the quarter, which is an improvement in customer attrition trends. Competition, lower revenue prices on acquisitions, renewals and conversions from month-to-month to fixed price contracts and supply costs based on forward market prices, will likely drive lower margins in the future.

  Operating Revenues

     Total operating revenues for the three months ended March 31, 2010 were $1.2 billion and consisted of the following:

• Mass revenues — totaled $713 million for the quarter from retail electric sales to approximately 1.5 million end use customers in the Texas market. Favorable weather, as compared to the 30-year HDD average, caused an increase in customer usage. Existing customer revenue rates led to strong Mass revenues. Partially offsetting these strong revenues were lower revenue pricing on acquisitions, renewals and conversions from month to month to fixed price contracts consistent with competitive offers.

• Commercial and Industrial revenue — C&I revenues for the three months ended March 31, 2010 totaled $489 million for the quarter on volume sales of approximately 6,209 GWh. Variable rate contracts tied to the market price of natural gas accounted for approximately 47% of the contracted volumes as of March 31, 2010.

• Supply management revenues — totaled $43 million for the quarter from the sale of excess supply into various markets in Texas.

• Contract amortization — reduced operating revenues by $69 million resulting from the amortization of C&I contracts acquired in the Reliant Energy acquisition.

  Cost of Energy

     Cost of energy for the three months ended March 31, 2010 was $1.2 billion and consisted of the following:

• Supply costs — totaled $617 million for the quarter. Energy is procured for fixed price term contracts at the time the sales contracts are executed. For month to month customers, the power is purchased at current market prices. Also, cooler weather for the period, as compared to the 30-year HDD average, caused an increase in purchased supply volumes. The supply costs were favorably impacted by $27 million of out of market supply contracts terminated in the fourth quarter 2009 in conjunction with the CSRA unwind.

• Transmission and distribution charges — totaled $300 million for the quarter for the cost to transport the power from the generation sources to the end use customers.

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• Risk management activities — totaled $288 million in unrealized losses on economic hedges related to supply contracts that were recognized for the three months ended March 31, 2010, and is comprised of $375 million of losses representing mark-to-market changes in the forward value of purchased electricity and gas and $3 million of losses related to the roll-off of previously recognized unrealized gains on settled economic positions offset by $90 million of gains representing a roll-off of loss positions acquired at May 1, 2009, valued at forward prices on that date. The roll-off amounts were offset by realized losses at the settled prices and higher costs of physical power which are reflected in the cost of operations during the same period.

• Financial settlements — totaled $35 million of losses for the quarter resulting from financial settlement of energy-related supply derivatives.

• Contract amortization — reduced the cost of energy by $10 million, resulting from amortization of supply contracts acquired in the Reliant Energy acquisition.

  Other Operating Expenses

     Other operating expenses for the three months ended March 31, 2010 were $103 million, or 9% of Reliant Energy’s total operating revenues. Other operating expenses consisted of the following:

• Selling, general and administrative expenses — totaled $49 million for the quarter. Total direct costs were $44 million, which primarily consisted of the costs of labor and external costs associated with advertising and other marketing activities, as well as human resources, community activities, legal, procurement, regulatory, accounting, internal audit, and management, as well as facilities leases and other office expenses. Indirect costs related to corporate allocations were $5 million.

• Operations and maintenance expenses — totaled $29 million for the quarter. These expenses primarily consisted of the labor and external costs associated with customer activities, including the call center, billing, remittance processing, and credit and collections, as well as the information technology costs associated with those activities.

• Gross receipts tax — totaled $16 million for the quarter or 1% of Mass and C&I revenues.

• Bad debt expense — totaled $9 million for the quarter or 1% of Mass and C&I revenues. During the quarter, Reliant Energy experienced improved customer payment behavior.

57

Results of Operations for Wholesale Power Generation Regions

     The following is a detailed discussion of the results of operations of NRG’s major wholesale power generation business segments.

  Texas

     For a discussion of the business profile of the Company’s Texas operations, see pages 97-101 of NRG Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2009.

  Selected Income Statement Data

(In millions except otherwise noted)
Three months ended March 31,	2010		2009		Change %
Operating Revenues
Energy revenue	$	628	$	594		6	%
Capacity revenue		7		47		(85	)
Risk management activities		212		263		(19	)
Contract amortization		2		15		(87	)
Other revenues		21		6		250
Total operating revenues		870		925		(6	)
Operating Costs and Expenses
Cost of energy (including risk management activities)		220		238		(8	)
Other operating expenses		182		168		8
Depreciation and amortization		117		117		—
Operating Income	$	351	$	402		(13	)
MWh sold (in thousands)		10,879		10,173		7
MWh generated (in thousands)		10,426		10,073		4
Business Metrics
Average on-peak market power prices ($/MWh)		41.86		32.60		28
Cooling Degree Days, or CDDs (a)		22		126		(83	)
CDD’s 30-year rolling average		94		94		—
Heating Degree Days, or HDDs (a)		1,385		903		53	%
HDD’s 30-year rolling average		1,122		1,122		—

(a) National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An 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.

  Operating Income

     Operating income decreased by $51 million for the three months ended March 31, 2010, compared to the same period in 2009, due to reduced capacity revenue of $40 million, higher fuel and purchased energy costs of $57 million, offset by higher net ancillary revenues of $4 million and increased net risk management activities of $37 million.

  Operating Revenues

     Total operating revenues decreased by $55 million during the three months ended March 31, 2010, compared to the same period in 2009, due to:

• Risk management activities — decreased by $51 million due to the difference between gains of $212 million for the three months ending March 31, 2010, compared to gains of $263 million during the same period in 2009. The $212 million gain included $203 million of unrealized mark-to-market gains and $9 million in gains on settled transactions, or financial income, compared to $225 million in unrealized mark-to-market gains and $38 million in financial gains during the same period in 2009. Please refer to Risk Management Activities in the consolidated Management’s Discussion and Analysis in this Form 10-Q for a more complete description of movements in risk management activities.

58

• Energy revenues — increased $34 million due to:

o Energy prices — increased by $14 million in the first quarter 2010 compared to the same period in 2009. The average realized energy price increased by 2%, driven by an 8% decrease in merchant prices offset by a 3% increase in contract prices.

o Generation — increased by 4% resulting in a $21 million increase in sales volume. This increase was driven by a 1% increase in coal plant generation, a 94% increase in gas plant generation, and a 97% increase in wind farm generation. These increases were offset by an 8% decrease in nuclear plant generation due to increased maintenance hours on STP Unit 1. Gas plant generation was supported by the Cedar Bayou 4 gas plant that went commercial in June 2009 and wind farm generation increased due to the Langford wind farm, which went commercial in December 2009. Coal plant generation was supported by reduced planned maintenance hours in 2010.

• Margin on MWh sold from market purchases — decreased by $1 million for the quarter.

• Capacity revenue — decreased by $40 million due to a lower proportion of contracts which contain a capacity component.

• Contract amortization revenue — resulting from the Texas Genco acquisition decreased by $13 million due to the reduced volume of contracted energy in 2010 as compared to 2009.

• Other revenue — increased by $15 million primarily due to higher ancillary services revenue of $16 million. Physical sales of natural gas and coal resulted in an increase of $5 million which was offset by $6 million in lower emissions credit revenue.

  Cost of Energy

     Cost of energy decreased by $18 million during the three months ended March 31, 2010, compared to the same period in 2009, due to:

• Fuel risk management activities — decreased $88 million due to gains of $23 million that were recorded for the three months ending March 31, 2010. The $65 million loss in 2009 included $56 million of unrealized mark-to-market losses, largely associated with forward coal positions and $9 million in losses on settled transactions, or financial cost of energy. Please refer to Risk Management Activities in the consolidated Management’s Discussion and Analysis in this Form 10-Q for a more complete description of movements in risk management activities.

These decreases were offset by:

• Natural gas costs — increased by $24 million due to a 26% increase in average natural gas prices per MMBtu and a 94% increase in gas-fired generation.

• Ancillary services costs — increased by $12 million due to an increase in purchased ancillary services costs incurred to meet obligations.

• Coal costs — increased by $17 million due to a $23 million increase in price driven by WA Parish transportation rate increases and Limestone fuel cost increases. This increase was offset by $10 million of lower WA Parish generation combined with $4 million in higher Limestone generation.

• Purchased energy — increased $16 million due to baseload units either unavailable or uneconomic to provide power for contract commitments and the assumption of Reliant Energy contracts.

• ISO Fees — increased $2 million due to the increased cost associated with the implementation of the nodal fee recovery by ERCOT.

     Other Operating Expenses

     Other operating expenses increased by $14 million during the three months ended March 31, 2010, compared to the same period in 2009, due to an increase in operations and maintenance expense as a result of maintenance outages at the region’s baseload plants.

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     Northeast Region

     For a discussion of the business profile of the Northeast region, see pages 101-105 of NRG Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2009.

Selected Income Statement Data

(In millions, except otherwise noted)
Three months ended March 31,	2010		2009		Change %
Operating Revenues
Energy revenue	$	121	$	181		(33	)%
Capacity revenue		104		96		8
Risk management activities		47		182		(74	)
Other revenues		7		5		40
Total operating revenues		279		464		(40	)
Operating Costs and Expenses
Cost of energy (including risk management activities)		87		117		(26	)
Other operating expenses		96		94		2
Depreciation and amortization		32		29		10
Operating Income	$	64	$	224		(71	)
MWh sold (in thousands)		2,389		2,637		(9	)
MWh generated (in thousands)		2,389		2,637		(9	)
Business Metrics
Average on-peak market power prices ($/MWh) (a)		52.87		58.29		(9	)
Cooling Degree Days, or CDDs (b)		—		—		—
CDD’s 30-year rolling average		—		—		—
Heating Degree Days, or HDDs (b)		2,853		3,207		(11	)%
HDD’s 30-year rolling average		3,094		3,093		—

(a)

MWh sold are shown net of MWh purchased to satisfy certain load contracts in the region.

(b)

National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An 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.

  Operating Income

     Operating income decreased by $160 million for the three months ended March 31, 2010, compared to the same period in 2009 due to:

• Operating revenues — decreased by $185 million due to unfavorable energy revenues and an unfavorable impact from risk management activities.

This decrease was offset by:

• Cost of energy — decreased by $30 million due to reduced fuel costs as a result of lower generation and lower prices.

  Operating Revenues

     Operating revenues decreased by $185 million for the three months ended March 31, 2010, compared to the same period in 2009, due to:

• Energy revenues — decreased by $60 million due to:

o Energy prices — decreased by $34 million reflecting an average 25% decline in realized energy prices, primarily from coal based generation.

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o Generation — decreased by $23 million due to an overall 9% decrease in generation in 2010 compared to 2009, with a 3% or $5 million decrease in coal generation and a 72% or $18 million decrease in oil and gas generation. Coal generation was down primarily due to the deactivation of Unit 6 of the Somerset coal plant in January 2010 while western New York and PJM was relatively flat compared to the same period in the prior year. Oil and gas generation was down due to a combination of planned and forced outages as well as reserve shutdowns primarily at Arthur Kill, Middletown and Oswego.

o Margin on MWh sold from market purchases — decreased by $3 million due to the expiration of a load contract in May 2009.

• Risk management activities — decreased by $135 million as gains of $47 million were recorded for the three months ending March 31, 2010, compared to gains of $182 million during the same period in 2009. The $47 million gain in 2010 included $14 million of unrealized mark-to-market gains and $33 million in gains on settled transactions, or financial income, compared to $122 million in unrealized mark-to-market gains and $60 million in financial income during the same period in 2009. The $122 million unrealized gain in 2009 included $107 million unrealized gain recognition of previously deferred amounts in accumulated OCI as a result of discontinuance of certain 2009 cash flow hedges on baseload plants generation due to lower forecasted generation. Please refer to Risk Management Activities in the consolidated Management’s Discussion and Analysis in this Form 10-Q for a more complete description of movements in risk management activities.

     These decreases were offset by:

• Capacity revenue — increased by $8 million due to higher pricing driven in part by the retirement of the Poletti facility in New York City in January 2010.

  Cost of Energy

• Cost of energy decreased by $30 million for the three months ended March 31, 2010, compared to the same period in 2009, due to:

o Natural gas and oil costs — decreased by $17 million, or 46%, due to 72% lower generation offset by 8% higher average natural gas prices.

o Coal costs — decreased by $6 million, or 7%, due to lower coal generation of 3% or $2 million primarily due to the Somerset plant deactivation and lower prices for $3 million.

o Fuel risk management activities — decreased $6 million as gains of $11 million were recorded in 2010 related primarily to mark-to-market gains, largely associated with forward coal positions, as compared to gains of $5 million in 2009, consisting of $9 million in mark-to-market gains and $4 million in losses on settled transactions, or financial cost of energy. Please refer to Risk Management Activities in the consolidated Management’s Discussion and Analysis in this Form 10-Q for a more complete description of movements in risk management activities.

o Carbon emission expense — decreased by $2 million due to 29% lower weighted average prices for RGGI credits held-for-use together with lower generation subject to RGGI carbon compliance.

     These decreases were offset by:

• Other operating costs — increased by $2 million due to a $14 million charge relating to the write-off of previously capitalized costs on the Indian River Unit 3 back-end controls project together with associated cancellation penalties. The write-offs and cancellation fees are due to the decision not to proceed with this project following a proposed agreement with DNREC to retire the unit by December 31, 2013. This charge was partially offset by $5 million lower general and administrative expenses largely driven by lower corporate allocations, and a change in estimate of $4 million for an asset retirement obligation liability at the Company’s Huntley and Dunkirk plants.

• Depreciation and amortization — increased by $3 million due to the acceleration of depreciation on assets for Indian River Unit 3 due to its anticipated early retirement as well as increased depreciation for the Dunkirk baghouse project, which came online in late 2009.

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     South Central Region

     For a discussion of the business profile of the South Central region, see pages 106-109 of NRG Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2009.

  Selected Income Statement Data

(In millions, except otherwise noted)
Three months ended March 31,	2010			2009			Change %
Operating Revenues
Energy revenue	$	106		$	96			10	%
Capacity revenue		57			68			(16	)
Risk management activities		(25	)		(7	)		(257	)
Contract amortization		5			6			(17	)
Other revenues		—			(1	)		—
Total operating revenues		143			162			(12	)
Operating Costs and Expenses
Cost of energy (including risk management activities)		97			110			(12	)
Other operating expenses		22			22			—
Depreciation and amortization		16			17			(6	)
Operating Income	$	8		$	13			(38	)
MWh sold (in thousands)		3,178			3,169			—
MWh generated (in thousands)		2,642			2,706			(2	)
Business Metrics
Average on-peak market power prices ($/MWh)		43.31			37.30			16
Cooling Degree Days, or CDDs (a)		—			6			—
CDD’s 30-year rolling average		31			31			—
Heating Degree Days, or HDDs (a)		2,241			1,805			24	%
HDD’s 30-year rolling average		1,895			1,895			—

(a) National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An 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.

  Operating Income

     Operating income decreased by $5 million as lower capacity revenues and higher purchased energy costs more than offset the increase in energy revenues and the drop in fuel costs for the three months ended March 31, 2010, compared to the same period in 2009.

  Operating Revenues

     Operating revenues decreased by $19 million for the three months ended March 31, 2010, compared to the same period in 2009, due to:

• Risk management activities — losses of $25 million were recorded for the three months ending March 31, 2010, compared to losses of $7 million during the same period in 2009. The $25 million loss included $13 million of unrealized mark-to-market losses and $12 million in losses on settled transactions, or financial income, compared to $20 million in unrealized mark-to-market losses and $13 million in financial gains during the same period in 2009. Please refer to Risk Management Activities in the consolidated Management’s Discussion and Analysis in this Form 10-Q for a more complete description of movements in risk management activities.

• Capacity revenues — capacity revenue decreased by $11 million due to contract expirations of $13 million offset by increased capacity charges of $2 million resulting from higher peak demand for the region’s cooperative customers.

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     These decreases were offset by:

• Energy revenues — increased by $10 million due to a $12 million increase in contract revenue coupled with a decrease of $2 million in merchant energy revenues. Total MWh sales to the region’s contract customers were up 9% while the average realized price on contract energy sales was $26.17 per MWh in 2010 compared to $23.37 per MWh in 2009. The rise in contract volume was due to colder weather in the first quarter of 2010, as total heating degree days for the period rose by 99%. Merchant energy revenues fell by $2 million. Megawatt hours sold to the merchant market decreased by 20% while merchant market prices rose by 20% to $56.41 per MWh.

  Cost of Energy

     Cost of energy decreased by $13 million for the three months ended March 31, 2010, compared to the same period in 2009, due to:

• Fuel risk management activities — gains of $10 million were recorded for the three months ending March 31, 2010. The $10 million gain included $11 million of unrealized mark-to-market gains, largely associated with forward coal positions and $1 million in losses on settled transactions, or financial cost of energy compared to $5 million in unrealized mark-to-market losses and $3 million in losses on settled transactions in the first quarter of 2009. Please refer to Risk Management Activities in the consolidated Management’s Discussion and Analysis in this Form 10-Q for a more complete description of movements in risk management activities.

• Coal expense — decreased $2 million as the average cost per ton was 4% below the 2009 average, reflecting lower fuel transportation surcharges partially offset by increased transportation contract rates.

These decreases were offset by:

• Purchased energy — Total purchased energy and capacity increased by $6 million because colder temperatures drove up load volumes and coal generation fell by 2%. Costs associated with energy from the region’s tolled facility increased by $4 million and costs of market purchases rose by $2 million.

Other Operating Expenses — were unchanged as a $2 million increase in major maintenance was offset by a $2 million decline in corporate allocations.

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       West Region

     For a discussion of the business profile of the West region, see pages 110-112 of NRG Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2009.

  Selected Income Statement Data

(In millions, except otherwise noted)
Three months ended March 31,	2010		2009			Change %
Operating Revenues
Energy revenue	$	8	$	2			N/A
Capacity revenue		26		29			(10	)%
Risk management activities		1		(3	)		N/A
Total operating revenues		35		28			25
Operating Costs and Expenses
Cost of energy (including risk management activities)		5		4			25
Other operating expenses		21		25			(16	)
Depreciation and amortization		3		2			50
Operating Income/(Loss)	$	6	$	(3	)		(300	)
MWh sold (in thousands)		69		14			393
MWh generated (in thousands)		69		14			393
Business Metrics
Average on-peak market power prices ($/MWh)		47.88		40.46			18
Cooling Degree Days, or CDDs (a)		—		—			—
CDD’s 30-year rolling average		7		7			—
Heating Degree Days, or HDDs (a)		1,330		1,410			(6	)%
HDD’s 30-year rolling average		1,419		1,419			—

(a) National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An 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.

  Operating Income

     Operating income increased by $9 million for the three months ended March 31, 2010, compared to the same period in 2009.

       Operating Revenues

     Operating revenues increased $7 million for the three months ended March 31, 2010, compared to the same period in 2009, due to:

• Energy revenue — increased by $6 million primarily due to an increase in merchant generation and merchant energy prices in 2010 compared to 2009. This increase includes a $1 million increase in energy revenue related to Blythe Solar, a new photovoltaic solar facility that began commercial operation in December 2009.

• Capacity revenue — decreased by $3 million primarily due to reduced resource adequacy and call option contract sales at El Segundo in 2010 compared to 2009.

• Risk management activities — a gain of $1 million was recognized during the quarter compared to a $3 million loss during the same period last year. An unrealized mark-to-market gain of $1 million during the quarter compared to an unrealized mark-to-market loss of $1 million during the same period last year. Also, there were no realized gains on settled transactions during the quarter compared to $2 million in realized losses on settled transactions during the same period last year. Please refer to Risk Management Activities in the consolidated Management’s Discussion and Analysis in this Form 10-Q for a more complete description of movements in risk management activities.

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Cost of Energy and Other Operating Expenses

     Cost of energy and other operating expenses decreased by $3 million for the three months ended March 31, 2010, compared to the same period in 2009, due to:

• Cost of energy — increased by $1 million due to an increase in natural gas consumption. This increase was offset by a decrease in fuel oil expense resulting from a 2009 write-down to market of fuel oil inventory no longer used in the production of energy.

• Other operating expenses — decreased by $4 million due to higher 2009 maintenance expenses associated with a major overhaul at El Segundo.

65

Liquidity and Capital Resources

Liquidity Position

     As of March 31, 2010, and December 31, 2009, NRG’s liquidity, excluding collateral received, was approximately $3.2 billion and $3.8 billion, respectively, and comprised of the following:

	March 31,			December 31,
(In millions)	2010			2009
Cash and cash equivalents	$	1,813		$	2,304
Funds deposited by counterparties		509			177
Restricted cash		7			2
Total cash		2,329			2,483
Synthetic Letter of Credit Facility availability		426			583
Revolving Credit Facility availability		964			905
Total liquidity		3,719			3,971
Less: Funds deposited as collateral by hedge counterparties		(509	)		(177	)
Total liquidity, excluding collateral received	$	3,210		$	3,794

     For the three months ended March 31, 2010, total liquidity, excluding collateral received, decreased by $584 million due to lower cash and cash equivalent balances of $491 million, decreased availability of the Synthetic Letter of Credit Facility of $157 million, partially offset by a $59 million increase in the $1.0 billion Revolving Credit Facility. Changes in cash and cash equivalent balances are further discussed below under the heading Cash Flow Discussion. Cash and cash equivalents and funds deposited by counterparties at March 31, 2010, were predominantly held in money market funds invested in treasury securities, treasury repurchase agreements or government agency debt.

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

     Management believes that the Company’s liquidity position and cash flows from operations will be adequate to finance operating and maintenance capital expenditures, to fund dividends to NRG’s preferred shareholders and other liquidity commitments. Management continues to regularly monitor the Company’s ability to finance the needs of its operating, financing and investing activity in a manner consistent with its intention to maintain a net debt to capital ratio in the range of 45-60%.

  SOURCES OF FUNDS

     The principal sources of liquidity for NRG’s future operating and capital expenditures are expected to be derived from new and existing financing arrangements, asset sales, existing cash on hand and cash flows from operations.

Financing Arrangements

Senior Credit Facility

     As of March 31, 2010, NRG had a Senior Credit Facility which is comprised of a senior first priority secured term loan, or the Term Loan Facility, the $1.0 billion Revolving Credit Facility, and the $1.3 billion Synthetic Letter of Credit Facility. The Senior Credit Facility was last amended on June 8, 2007. As of March 31, 2010, NRG had issued $874 million of letters of credit under the Synthetic Letter of Credit Facility, leaving $426 million available for future issuances. Under the Revolving Credit Facility, as of March 31, 2010, NRG had issued a letter of credit of $36 million leaving $864 million available for future letter of credit issuances.

66

  Merrill Lynch Credit Sleeve Facility

     On April 28, 2010, Merrill Lynch agreed to continue to provide credit support to four Reliant Energy counterparties under the Amended CSRA through December 15, 2010. The Company intends to have no Reliant Energy counterparties under the Amended CSRA by December 15, 2010.

  TANE Facility

     On February 24, 2009, NINA executed an Engineering, Procurement and Construction, or EPC, agreement with TANE, which specifies the terms under which STP Units 3 and 4 will be constructed. Concurrent with the execution of the EPC agreement, NINA and TANE entered into the TANE Facility, wherein TANE has committed up to $500 million to finance purchases of long-lead materials and equipment for the construction of STP Units 3 and 4. The TANE Facility matures on February 24, 2012, subject to two renewal periods, and provides for customary events of default, which include, among others: nonpayment of principal or interest; default under other indebtedness; the rendering of judgments; and certain events of bankruptcy or insolvency. Outstanding borrowings will accrue interest at LIBOR plus 3%, subject to a ratings grid, and are secured by substantially all of the assets of and membership interests in NINA and its subsidiaries. As of March 31, 2010, no amounts have been borrowed under the TANE Facility.

  Dunkirk Power LLC Tax-Exempt Bonds

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

  GenConn Energy LLC related financings

     NRG Connecticut Peaking Development LLC made funding requests under the EBL during the quarter. The EBL is backed by a letter of credit issued by NRG under its Synthetic Letter of Credit Facility equal to 104% of the amount outstanding. The proceeds of the EBL received through March 31, 2010, were $114 million and the remaining amounts will be drawn as necessary to fund interest on the EBL as the maximum amount permitted to be drawn for project costs for both projects has been met.

     In April 2009, GenConn secured financing for 50% of the Devon and Middletown project construction costs through a seven-year term loan facility, and also entered into a five-year revolving working capital loan and letter of credit facility, which collectively with the term loan is referred to as the GenConn Facility. The aggregate credit amount secured under the GenConn Facility, which is non-recourse to NRG, is $291 million, including $48 million for the revolving facility. In August 2009, GenConn began to draw under the GenConn Facility to cover costs related to the Devon project. As of March 31, 2010, $75 million had been drawn.

First and Second Lien Structure

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

     The Company’s lien counterparties may have a claim on its assets to the extent market prices exceed the hedged price. As of March 31, 2010, and April 23, 2010, all hedges under the first and second liens were in-the-money on a counterparty aggregate basis.

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     The following table summarizes the amount of MWs hedged against the Company’s baseload assets and as a percentage relative to the Company’s net baseload capacity under the first and second lien structure as of April 23, 2010:

Equivalent Net Sales Secured by First and Second Lien Structure (a)	2010			2011			2012			2013
In MW (b)		3,145			2,781			1,441			739
As a percentage of total net baseload capacity (c)		46	%		41	%		21	%		11	%

(a)	Equivalent Net Sales include natural gas swaps converted using a weighted average heat rate by region.
(b)	2010 MW value consists of May through December positions only.
(c)	Net baseload capacity under the first and second lien structure represents 80% of the Company’s total baseload assets.

  USES OF FUNDS

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

  Commercial Operations

     NRG’s commercial operations activities require a significant amount of liquidity and capital resources. These liquidity requirements are primarily driven by: (i) margin and collateral posted with counterparties; (ii) initial collateral required to establish trading relationships; (iii) timing of disbursements and receipts (i.e., buying fuel before receiving energy revenues); and (iv) initial collateral for large structured transactions. As of March 31, 2010, commercial operations had total cash collateral outstanding of $533 million, and $573 million outstanding in letters of credit to third parties primarily to support its economic hedging activities for both wholesale and retail transactions (includes a $55 million deposit at the PUCT that covers outstanding customer deposits and residential advance payments). As of March 31, 2010, total collateral held from counterparties was $509 million in cash and $11 million of letters of credit.

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

     Debt Service Obligations

     NRG must annually offer a portion of its excess cash flow, as defined in the Senior Credit Facility, to its first lien lenders under the Term Loan Facility. The percentage of excess cash flow offered to these lenders is dependent upon the Company’s consolidated leverage ratio, as defined in the Senior Credit Facility, at the end of the preceding year. Of the amount offered, the first lien lenders must accept 50% while the remaining 50% may either be accepted or rejected at the lenders’ option. In March 2010, NRG made and the lenders accepted a repayment of approximately $229 million for the mandatory annual offer relating to 2009.

     As of March 31, 2010, NRG had issued approximately $5.4 billion in aggregate principal amount of unsecured high yield notes, or Senior Notes, had approximately $2.0 billion in principal amount outstanding under the Term Loan Facility, and had issued $874 million of letters of credit under the Company’s $1.3 billion Synthetic Letter of Credit Facility and $36 million of letters of credit under the Company’s Revolving Credit Facility. The Revolving Credit Facility matures on February 2, 2011, and the Synthetic Letter of Credit Facility matures on February 1, 2013.

  Debt Related to Capital Allocation Program

     On March 3, 2010, the Company completed the early unwinding of the CSF I Debt by remitting a cash payment to CS of $242 million to settle the outstanding principal and interest, as compared to $249 million that would have been due at maturity in June 2010. The Company has now settled all obligations related to the CSF I and II Debt entered into in 2006, as amended from time to time, as well as the SLA entered into in February 2009.

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     Capital Expenditures

     For the three months ended March 31, 2010, the Company’s capital expenditures, including accruals, were approximately $264 million. The following table summarizes the Company’s capital expenditures for the three months ended March 31, 2010, and the estimated capital expenditure and repowering investments forecast for the remainder of 2010.

(In millions)	Maintenance		Environmental		Repowering		Total
Northeast	$	3	$	41	$	—	$	44
Texas		31		—		—		31
South Central		6		—		—		6
West		1		—		—		1
Nuclear development		—		—		170		170
Other		10		—		2		12
Total	$	51	$	41	$	172	$	264
Estimated capital expenditures for the remainder of 2010	$	196	$	153	$	508	$	857

     RepoweringNRG capital expenditures — RepoweringNRG project capital expenditures consisted of approximately $170 million related to the development of STP Units 3 and 4 in Texas.

     NRG’s net expenditures for STP Units 3 and 4 for 2010, funded from operating activities, are anticipated to be approximately $328 million. In addition, NINA anticipates net funding of approximately $332 million of 2010 capital expenditures from sources other than NRG, including drawings on the TANE long-lead material facility, Toshiba equity contributions, and TEPCO equity contributions. NINA is also soliciting additional equity participants, which will serve to reduce NRG’s projected net expenditures to the extent new partner contributions are received in 2010. If this project does not receive a loan guarantee from the U.S. Department of Energy, or U.S. DOE, it is the intention of the Company, in consultation with its partners, to reduce project expenditures significantly and immediately. This may result in a reassessment of the probability of success of the project and an impairment of the value of the capitalized assets for STP Units 3 and 4. An impairment would result in a permanent write-down of $389 million of construction-in-progress capitalized through March 31, 2010, plus any amounts capitalized through the impairment date.

     Major maintenance and environmental capital expenditures — The Company’s maintenance capital expenditures were $51 million, of which $31 million was related to the Texas region’s assets, including approximately $15 million in nuclear fuel expenditures related to STP Units 1 and 2. The Company’s environmental capital expenditures were $41 million, of which $36 million was due to a project to install selective catalytic reduction systems, scrubbers and fabric filters on Indian River Unit 4 with an expected in service date of year end 2011.

     Loans to affiliates — The equity portion of construction costs for GenConn is funded through the EBLs of NRG Connecticut Peaking and The United Illuminating Company, or United Illuminating. These funds are made available to GenConn through interest bearing promissory notes that convert to equity upon repayment of the EBL loans by NRG Connecticut Peaking and United Illuminating. As of March 31, 2010, there was $113 million outstanding under the loan from NRG Connecticut Peaking.

     Environmental Capital Expenditures

     Based on current rules, technology and plans, NRG has estimated that environmental capital expenditures from 2010 through 2014 to meet NRG’s environmental commitments will be approximately $0.9 billion. These capital expenditures, in general, are related to installation of particulate, SO₂, NO_x, and mercury controls to comply with federal and state air quality rules and consent orders, as well as installation of “Best Technology Available” under the Phase II 316(b) Rule. NRG continues to explore cost effective alternatives that can achieve desired results. While this estimate reflects schedules and controls to meet anticipated reduction requirements, the full impact on the scope and timing of environmental retrofits cannot be determined until issuance of final rules by the U.S. EPA.

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

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

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  Capital Allocation

     2010 Capital Allocation Plan — On February 23, 2010, the Company announced its 2010 Capital Allocation Plan to purchase $180 million in common stock. The Company’s share repurchases are subject to market prices, financial restrictions under the Company’s debt facilities, and as permitted by securities laws. As part of the 2010 Capital Allocation Plan, the Company will invest approximately $349 million in maintenance and environmental capital expenditures in existing assets and $508 million in projects under RepoweringNRG that are currently under construction or for which there exist current obligations. Finally, in addition to scheduled debt amortization payment, in the first quarter 2010, the Company paid its first lien lenders $229 million of its 2009 excess cash flow, as defined in the Senior Credit Facility.

  Preferred Stock Dividend Payments

     For the three months ended March 31, 2010, NRG paid approximately $2 million in dividend payments to holders of the Company’s 3.625% Preferred Stock.

  Reliant Energy Customer Deposits

     Revisions in the PUCT rules will require that NRG keep a segregated account, or that the Company post a fully collateralized letter of credit on or before May 21, 2010, to cover outstanding customer deposits and residential advance payments. The Company filed an amendment to its Retail Electric Provider certificate in the first quarter of 2010, which was approved by the PUCT, and posted a letter of credit to satisfy the rule changes. The amount of deposits subject to segregation as of March 31, 2010, was approximately $55 million.

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Cash Flow Discussion

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

(In millions)
Three months ended March 31,	2010			2009			Change
Net cash provided by operating activities	$	114		$	139		$	(25	)
Net cash used by investing activities		(194	)		(259	)		65
Net cash used by financing activities		(408	)		(184	)		(224	)

  Net Cash Provided By Operating Activities

     For the three months ended March 31, 2010, net cash provided by operating activities decreased by $25 million compared to the same period in 2009, due to:

• Lower cash flows from Wholesale Power Generation — The Company’s cash flow from operating activities excluding Reliant Energy was lower by $250 million mainly due to a $169 million decrease in operating income adjusted for non-cash charges and a $98 million decrease in net collateral deposits paid and option premiums paid and collected for 2010 as compared to the same period in 2009.

• Cash generated by Reliant Energy — Reliant Energy contributed approximately $225 million to the Company’s consolidated cash flow from operating activities in the first quarter 2010, primarily reflecting $215 million in operating income during the quarter, adjusted for non-cash charges related to bad debt expense, depreciation and amortization expense, and unrealized losses on energy supply derivatives. In addition, a seasonal decrease in accounts receivable of $50 million partially offset by a $29 million decrease in accrued expenses and other current liabilities also positively impacted Reliant Energy’s cash flow from operations.

  Net Cash Used By Investing Activities

     For the three months ended March 31, 2010, net cash used by investing activities decreased by $65 million compared to the same period in 2009, due to:

• Capital expenditures — NRG’s capital expenditures decreased by $48 million due to decreased spending on RepoweringNRG and environmental projects.

• Proceeds from sale of assets — Net proceeds increased by $26 million in 2010 as compared to 2009 due to the sale of Padoma in January 2010 for net proceeds of $29 million.

  Net Cash Used By Financing Activities

     For the three months ended March 31, 2010, net cash used by financing activities increased by $224 million compared to 2009, due to:

• Term Loan Facility debt payment — In 2010, the Company paid down $237 million of its Term Loan Facility, including the payment of excess cash flow, as discussed above under Debt Service Obligations. The Company paid down $205 million of its Term Loan Facility during 2009 which resulted in a net cash decrease of $32 million.

• CSF I Debt — During 2010, the Company paid $190 million in principal to early settle the CSF I Debt compared to no payments made in 2009.

• Net receipt from acquired derivatives that include financing elements — In 2010, the Company received a net of $13 million for the settlement of gas swaps related to Reliant Energy and Texas Genco compared to a receipt of $40 million for 2009 related to Texas Genco, for a net decrease in cash of $27 million.

• Preferred dividends — During the three months ended March 31, 2010, dividend payments on preferred stock decreased by $12 million as compared to the same period in 2009 due to the conversion of the 5.75% Preferred Stock in 2009 and the conversion of the 4% Preferred Stock, which was completed in January 2010.

• Issuance of debt — During 2010, the Company issued $10 million under existing debt facilities as compared to no issuance of debt in 2009.

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

     As of March 31, 2010, the Company had generated total domestic pre-tax book income of $112 million and foreign pre-tax book income of $11 million. The Company has net operating losses for tax return purposes available to offset taxable income in the current period. In addition, NRG has cumulative foreign NOL carryforwards of $268 million, of which $82 million will expire starting in 2011 through 2017 and of which $186 million do not have an expiration date.

     In addition to these amounts, the Company has $630 million of tax effected unrecognized tax benefits which relate primarily to net operating losses for tax return purposes but have been classified as capital loss carryforwards for financial statement purposes and for which a full valuation allowance has been established. As a result of the Company’s tax position, and based on current forecasts, NRG anticipates income tax payments, primarily due to foreign, state and local jurisdictions, of up to $75 million in 2010.

     However, as the position remains uncertain for the $630 million of tax effected unrecognized tax benefits, the Company has recorded a non-current tax liability of $423 million and may accrue the remaining balance as an increase to non-current liabilities until final resolution with the related taxing authority. The $423 million non-current tax liability for unrecognized tax benefits is primarily due to taxable earnings for which there are no NOLs available to offset for financial statement purposes.

     The Company is under examination by the Internal Revenue Service for years 2004 through 2006.

New and On-going Company Initiatives and Development Projects

     FORNRG Update

     Beginning in January 2009, the Company transitioned to FORNRG 2.0 to target an incremental 100 basis point improvement to the Company’s ROIC by 2012. The initial targets for FORNRG 2.0 were based upon improvements in the Company’s ROIC as measured by increased cash flow. The economic goals of FORNRG 2.0 will focus on: (i) revenue enhancement; (ii) cost savings; and (iii) asset optimization, including reducing excess working capital and other assets. The FORNRG 2.0 program will measure its progress towards the FORNRG 2.0 goals by using the Company’s 2008 financial results as a baseline, while plant performance calculations will be based upon the appropriate historic baselines.

     The 2010 FORNRG goal is 65 basis points improvement, which corresponds to approximately $98 million in cash flows. The goal is inclusive of benefits created in 2009 and new project benefits reported in 2010. As of the first quarter 2010, the Company has delivered a 13 basis point improvement in ROIC, which is equivalent to approximately $20 million in cash flows to the FORNRG program. During 2010, the Company expects to progress further toward the program goal of 100 basis point ROIC improvement by 2012.

RepoweringNRG Update

     NRG has several projects in varying stages of development that include the following: a new generating unit at the Limestone power station, the repowering of the Encina and El Segundo sites, and a combined heat and power system for the University Medical Center of Princeton. The development of these projects is subject to certain conditions and milestones which may affect the Company’s decision to pursue further development of these projects. The Company’s development projects are generally subject to certain conditions, milestones, or other factors that may result in the Company’s decision to no longer pursue development of these projects.

     On March 9, 2010, NRG was selected by the U.S. DOE to negotiate to receive up to $154 million, including funding from the American Recovery and Reinvestment Act, to build a 60 MW post-combustion carbon capture demonstration unit at NRG’s WA Parish plant southwest of Houston with use of the captured carbon in enhanced oil recovery in adjacent oil fields. The proposed project was submitted under the Clean Coal Power Initiative Program, or CCPI, a cost-shared collaboration between the federal government and private industry to demonstrate low-emission carbon capture and storage technologies in advanced coal-based, power generation. The Company is in the process of negotiating a cooperative agreement with the U.S. DOE which will define the basis for cost sharing in the development and initial operations of the facility. Construction is planned to start in early 2012 with commercial operations anticipated in the fourth quarter 2013.

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     The following is a summary of the 2010 repowering projects that are currently under construction. In addition, NRG continues to participate in active bids in response to requests for proposals in markets in which it operates.

  Plants under Construction

     GenConn Energy LLC — GenConn Energy, a 50/50 joint venture of NRG and The United Illuminating Company, or United Illuminating, formed to construct, own and operate peaking generation facilities in Connecticut, is in the construction phase of two, 200 MW peaking facilities at NRG’s Devon and Middletown sites. Each of these facilities is being constructed pursuant to 30-year contracts for differences with The Connecticut Light & Power Company. The GenConn Devon facility has a target commercial operation date of June 1, 2010, and the GenConn Middletown facility’s target commercial operation date is June 1, 2011. Both projects are fully permitted, and major construction is nearing completion on the Devon project. The Middletown project is in the early stages of construction.

     GenConn was directed by the Connecticut Department of Public Utility Control to bid the full capacity of the GenConn Devon facility into the ISO-NE locational forward reserve auction for the summer 2010 period (June 1, 2010 — September 30, 2010). If one or more units are delayed and GenConn does not have the capacity, or cannot procure replacement capacity, to meet its reserve obligation as of June 1, 2010, GenConn will be assessed ISO-NE penalties for the difference between the cleared GenConn Devon capacity and the facility’s available capacity. NRG’s share of such penalties, if incurred, however, are not expected to be material. Currently, GenConn expects that the Devon units will achieve commercial operations in June 2010.

     In April 2009, GenConn Energy closed on $534 million of project financing related to these projects. The project financing includes a seven-year project backed term loan and a five-year working capital facility which together total $291 million. In addition, NRG and United Illuminating have each closed an equity bridge loan of $121.5 million, which together total $243 million. NRG is funding its share of costs related to these projects via draw downs on the equity bridge loan totaling $114 million as of March 31, 2010. GenConn began to draw on the project financing facility to cover costs related to the Devon project in August 2009. As of March 31, 2010, $75 million had been drawn.

Retail Development

   Electric Vehicle Services

     In 2009, NRG began development of a service business to support the mass deployment of electric vehicles through its subsidiary Reliant Energy. In 2010, Reliant Energy plans to begin selling new products and services that enable both public and home charging of electric vehicles. In conjunction with this effort, Reliant Energy announced in November 2009 that it will work with Nissan Motor Co. to make the City of Houston a launch city for the broader use of electric vehicles. In November 2009, Reliant Energy announced a joint project with the City of Houston to add plug-in fleet vehicles as well as public charging stations to support them. In March 2010, NRG invested in Aptera Motors, Inc., a privately held electric vehicle, or EV, manufacturer expected to launch a production EV in 2011.

  Smart Energy

     In the fourth quarter 2009, Reliant Energy was awarded a $20 million grant in the Smart Grid Investment Grant Program for a three-year project to bring a suite of Smart Grid enabled products to residential customers. Reliant Energy and the Department of Energy finalized the grant agreement in March 2010. This project is in progress and includes an accelerated deployment of smart meter enabled products as well as services that provide energy usage insights, choices, and controls to homes of consumers across the competitive regions of Texas.

Nuclear Innovation North America

     NINA, NRG’s majority-owned subsidiary, is focused on marketing, siting, developing, financing and investing in new advanced design nuclear projects in select markets across North America, including the planned South Texas Units 3 and 4 project, or the STP Units 3 and 4 Project. TANE, a wholly-owned subsidiary of Toshiba Corporation, is the minority owner of NINA. Based on its current NRC schedule, the Company expects to achieve commercial operation for Unit 3 in 2016 and commercial operation for Unit 4 approximately 12 months thereafter. The total rated capacity of STP Units 3 and 4 is expected to equal or exceed 2,700 MW.

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     The U.S. DOE has confirmed that the STP Units 3 and 4 Project is one of four projects selected for further due diligence and negotiation leading to a conditional commitment under the U.S. DOE loan guarantee program. NINA is currently in discussions with the U.S. DOE on the specific terms and amount to be loaned for the project. NRG believes U.S. DOE loan guarantee support is critical to new nuclear development projects. In addition to U.S. loan guarantees, NINA is seeking to augment potential financial support from the U.S. DOE by actively pursuing additional loan guarantees through the Japanese government.

     On March 1, 2010, an agreement was reached with CPS for NINA to acquire a controlling interest in the STP Units 3 and 4 Project to construct it through a settlement of the litigation between the parties. As part of the agreement, NINA increased its ownership in the STP Units 3 and 4 Project from 50% to 92.375% and assumed full management control of the project. NRG also will pay $80 million to CPS, subject to receipt of a conditional U.S. DOE loan guarantee. The first $40 million would be promptly paid after receipt of the guarantee with the remaining $40 million paid six months later. An additional $10 million will be donated by NRG over four years in annual payments of $2.5 million to the Residential Energy Assistance Partnership, or REAP, in San Antonio. The first $2.5 million payment to REAP was made on March 17, 2010. In connection with the agreement, the Company capitalized $90 million to construction in progress within property, plant and equipment, and as of March 31, 2010, $80 million in other current liabilities and $7.5 million in other non-current liabilities remains on the condensed consolidated balance sheet for the obligations to CPS and REAP. As part of the agreement with CPS, all litigation was dismissed with prejudice.

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

     On May 10, 2010, NINA and TEPCO Nuclear Energy America LLC, or TNEA, a wholly-owned subsidiary of The Tokyo Electric Power Company of Japan, Inc., signed an Investment and Option Agreement whereby TNEA agreed to acquire up to a 20% interest in NINA Investments Holdings LLC, or Holdings. Holdings is a wholly-owned subsidiary of NINA, which indirectly holds NINA’s ownership interest in the STP Units 3 and 4 Project. TNEA will initially invest $155 million for a 10% share of Holdings, which includes a $30 million option premium payment to Holdings. This option, which expires approximately one year-from the date of signing the Investment and Option Agreement, will enable TNEA to buy an additional 10% of Holdings for another payment of $125 million. The closing is contingent upon NINA’s receipt of a U.S. DOE loan guarantee commitment. Upon its initial investment, TNEA will hold a 9.2375% interest in the STP Units 3 and 4 Project, bringing NINA’s investment down to 83.1375%. If TNEA exercises its option to increase its ownership of Holdings by an additional 10%, it will own 18.475% of the STP Units 3 and 4 Project, bringing NINA’s investment down to 73.90%.

Renewable Development

     NRG has routinely invested in the development of renewable energy projects such as wind, solar and biomass, to support the Company’s econrg initiative. NRG’s renewable strategy is to capitalize on both first mover advantages and the Company’s inherent regional presence. The following are the renewable development projects the Company is actively engaged in:

     Solar Development

     NRG is developing a number of solar projects utilizing photovoltaic, or PV, as well as solar thermal technologies, including the eSolar technology. Specifically, NRG has a 284 MW off-take agreement with Southern California Edison, a 66 MW off-take agreement with Pacific Gas & Electric, and a 92 MW off-take agreement with El Paso Electric that will utilize PV, solar thermal or a combination of the two technologies. While each of these projects has a power purchase agreement, or PPA, in place, the development of these projects is subject to certain regulatory approvals, conditions and milestones which may affect the Company’s decision to pursue further development of one or more of these projects.

     Consistent with its business strategy, NRG is currently focused on early stage development efforts in a number of markets as well as conducting due diligence in respect to various equity investment opportunities for solar projects utilizing solar technologies that range from concentrated solar thermal to photovoltaic.

     Wind Development

     South Trent Wind Farm

     On March 2, 2010, NRG signed a binding letter of intent to purchase South Trent Wind Farm LLC, owner of the South Trent wind farm, or South Trent, a 101 megawatt wind farm near Sweetwater, Texas. South Trent went commercial in January 2009 and consists of 44 turbines producing up to 2.3 MW of power each. The project has a 20-year PPA for all generation from the site. The proposed acquisition is pending approval by the PUCT and satisfaction of certain other conditions, and is expected to close in the second quarter 2010.

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     Offshore Wind

     Through its subsidiary NRG Bluewater Holdings LLC, or NRG Bluewater, the Company is actively pursuing development of offshore wind projects along the Atlantic Coast of the northeastern U.S. and in the Great Lakes. NRG Bluewater’s Mid-Atlantic Wind Park is the most advanced of these projects, with a signed PPA for 238 MW and several additional off-take agreements under negotiation. NRG Bluewater also holds leases to erect a meteorological tower at the site of the Mid-Atlantic Wind Park and at the site of its proposed project off the coast of New Jersey.

     On April 26, 2010, the U.S. Department of Interior through the Minerals Management Service issued a request for interest, or RFI, in obtaining one or more commercial leases for the construction of a wind energy project on the Outer Continental Shelf off the coast of Delaware. The RFI process will determine if there is competitive interest in building on an ocean tract starting 7.5 miles due east of Rehoboth Beach, Delaware. NRG Bluewater plans to build the Mid-Atlantic Wind Park in an area inside this zone 13 miles from shore, running to more than 20 miles from shore for the farthest turbine. Responses must be submitted by June 25, 2010, and NRG Bluewater is planning to participate in this RFI.

     Biomass Development

     In April 2010, the Company was awarded a 10-year contract from the New York State Energy Research and Development Authority for power generated using renewable biomass fuel at its Dunkirk Generating Station in western New York. The project, which is expected to come online by the end of 2011, will produce up to 15 MW of the station’s total output by co-firing with clean wood biomass. The award was part of a competitive solicitation to award contracts for projects that deliver renewable energy to the New York wholesale power market and which will help the state reach its RPS goal to increase the proportion of renewable electricity sold in New York from 25 percent to 30 percent by 2015.

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

Off-Balance Sheet Arrangements

     Obligations under Certain Guarantee Contracts

     NRG and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include financial and performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. See Note 18, Guarantees, to this Form 10-Q for additional discussion.

     Retained or Contingent Interests

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

     Derivative Instrument Obligations

     The Company’s 3.625% Preferred Stock includes a feature which is considered an embedded derivative per ASC 815. Although it is considered an embedded derivative, it is exempt from derivative accounting as it is excluded from the scope pursuant to ASC 815. As of March 31, 2010, based on the Company’s stock price, the embedded derivative was out-of-the-money and had no redemption value.

  Obligations Arising Out of a Variable Interest in an Unconsolidated Entity

     Variable Interest in Equity Investments — As of March 31, 2010, NRG has several investments with an ownership interest percentage of 50% or less in energy and energy-related entities that are accounted for under the equity method of accounting. Two of these investments, GenConn Energy LLC and Sherbino, are variable interest entities for which NRG is not the primary beneficiary.

     NRG’s pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $105 million as of March 31, 2010. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG.

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     Letter of Credit Facilities — The Company’s $1.3 billion Synthetic Letter of Credit Facility is unfunded by NRG and is secured by a $1.3 billion cash deposit at Deutsche Bank AG, that was funded using proceeds from the Term Loan Facility investors who participated in the facility syndication. Under the Synthetic Letter of Credit Facility, NRG is allowed to issue letters of credit for general corporate purposes including posting collateral to support the Company’s commercial operations activities.

  Contractual Obligations and Commercial Commitments

     NRG has a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to the Company’s capital expenditure programs, as disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009. Also see Note 15, Commitments and Contingencies, to this Form 10-Q for a discussion of new commitments and contingencies that also include contractual obligations and commercial commitments that occurred during the three months ended March 31, 2010.

Critical Accounting Policies and Estimates

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

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

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

     As described in Critical Accounting Policies and Estimates — Goodwill and Other Intangible Assets, in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009, the Company believes that assumptions about future power prices most significantly impact the fair value of its Texas reporting unit. The price of natural gas plays an important role in setting the price of electricity in many of the regions where NRG operates power plants, and forward natural gas prices have continued to decline since year-end 2009. If long-term natural gas prices remain depressed for an extended period of time, the Company’s goodwill may become impaired in the future, which would result in a charge against earnings.

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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. In order to manage these risks, the Company uses various fixed-price forward purchase and sales contracts, futures and option contracts traded on the New York Mercantile Exchange, and swaps and options traded in the over-the-counter financial markets to:

• Manage and hedge fixed-price purchase and sales commitments;

• Manage and hedge exposure to variable rate debt obligations;

• Reduce exposure to the volatility of cash market prices; and

• Hedge fuel requirements for the Company’s generating facilities.

  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. A number of factors influence the level and volatility of prices for energy commodities and related derivative products. These factors include:

• Seasonal, daily and hourly changes in demand;

• Extreme peak demands due to weather conditions;

• Available supply resources;

• Transportation availability and reliability within and between regions; and

• Changes in the nature and extent of federal and state regulations.

     NRG’s portfolio consists of generation assets and wholesale transactions load serving obligations. 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. These instruments include forwards, futures, swaps, and option contracts traded on various exchanges, such as New York Mercantile Exchange, or NYMEX, Intercontinental Exchange, or ICE, and Chicago Climate Exchange, or CCX, as well as over-the-counter financial markets. The portion of forecasted transactions hedged may vary based upon management’s assessment of market, weather, the projected operations of our generation assets and other factors.

     While some of the contracts the Company uses to manage risk represent commodities or instruments for which prices are available from external sources, other commodities and certain contracts are not actively traded and are valued using other pricing sources and modeling techniques to determine expected future market prices, contract quantities, or both. NRG uses the Company’s best estimates to determine the fair value of those derivative contracts. However, it is likely that future market prices could vary from those used in recording mark-to-market derivative instrument valuation, and such variations could be material.

     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. VaR is a statistical model that attempts to predict risk of loss based on market price and volatility. Currently, the company estimates VaR using a Monte Carlo simulation based methodology.

     NRG uses a diversified VaR model to calculate an estimate of the potential loss in the fair value of the Company’s energy assets and liabilities, which includes generation assets, load obligations, and bilateral physical and financial transactions. The key assumptions for the Company’s diversified model include: (i) a lognormal distribution of prices; (ii) one-day holding period; (iii) a 95% confidence interval; (iv) a rolling 36-month forward looking period; and (v) market implied volatilities and historical price correlations.

77

     As of March 31, 2010, the VaR for NRG’s commodity portfolio, including generation assets, load obligations and bilateral physical and financial transactions calculated using the diversified VaR model was $51 million.

     The following table summarizes average, maximum and minimum VaR for NRG for the three months ended March 31, 2010, and 2009:

(In millions)
VAR	2010		2009
Three months ended March 31:	$	51	$	35
Average		47		41
Maximum		55		50
Minimum		37		34

     Due to the inherent limitations of statistical measures such as VaR, the evolving nature of the competitive markets for electricity and related derivatives, and the seasonality of changes in market prices, the VaR calculation may not capture the full extent of commodity price exposure. As a result, actual changes in the fair value of mark-to-market energy assets and liabilities could differ from the calculated VaR, and such changes could have a material impact on the Company’s financial results.

     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, 2010, for the entire term of these instruments entered into for both asset management and trading, was approximately $38 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.

     As of March 31, 2010, the Company had various interest rate swap agreements with notional amounts totaling approximately $3.1 billion. If the swaps had been discontinued on March 31, 2010, the Company would have owed the counterparties approximately $101 million. Based on the investment grade rating of the counterparties, NRG believes its exposure to credit risk due to nonperformance by counterparties to its hedge contracts to be immaterial.

     NRG has both long- and short-term debt instruments that subject the Company to the risk of loss associated with movements in market interest rates. As of March 31, 2010, a 1% change in interest rates would result in a $10 million change in interest expense on a rolling twelve month basis.

     As of March 31, 2010, the Company’s long-term debt fair value was $7.8 billion and the carrying amount was $7.9 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 $426 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. NRG’s liquidity management framework is intended to maximize liquidity access and minimize funding costs. Through active liquidity management, the Company seeks to preserve stable, reliable and cost-effective sources of funding. This enables the Company to replace maturing obligations when due and fund assets at appropriate maturities and rates. To accomplish this task, management uses a variety of liquidity risk measures that take into consideration market conditions, prevailing interest rates, liquidity needs, and the desired maturity profile of 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.

78

     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 $222 million as of March 31, 2010, and a 0.25 MMBtu/MWh change in heat rates for heat rate positions would result in a change in margin collateral posted of approximately $21 million as of March 31, 2010. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of March 31, 2010.

     Under the second lien, NRG is required to post certain letters of credit as credit support for changes in commodity prices. As of March 31, 2010, no letters of credit are outstanding to second lien counterparties. With changes in commodity prices, the letters of credit could grow to $64 million, the cap under the agreements.

  Credit Risk

     Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. NRG is exposed to counterparty credit risk through various activities including wholesale sales, fuel purchases and retail supply and retail customer credit risk through its retail load activities.

     Counterparty Credit Risk

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

     As of March 31, 2010, total counterparty credit exposure to substantially all counterparties was $1.7 billion and NRG held cash collateral against those positions of $509 million resulting in a net exposure of $1.2 billion. Total counterparty credit exposure is discounted at the risk free rate.

     The following table highlights the 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 NPNS, and non-derivative transactions. The exposure is shown net of collateral held, includes amounts net of receivables or payables.

	Net Exposure (a)
Category	(% of Total)
Financial institutions		67	%
Utilities, energy, merchants, marketers and other		30
Coal suppliers		1
ISOs		2
Total as of March 31, 2010		100	%

	Net Exposure (a)
Category	(% of Total)
Investment grade		80	%
Non-Investment grade		1
Non-rated		19
Total as of March 31, 2010		100	%

(a) Counterparty credit exposure excludes California tolling, Northeast load obligations, New England Reliability Must-Run, or RMR, certain cooperative load contracts, and Texas Westmoreland coal contracts. The aforementioned exposures were excluded for various reasons including regulatory support or liens held against the contracts which serve to reduce the risk of loss. NRG also excludes uranium and coal transportation contracts from counterparty credit exposure because of the illiquidity of the reference markets. Credit exposure also excludes any exposure NRG has to counterparties of non-recourse subsidiaries.

     NRG has counterparty credit risk exposure to certain counterparties representing more than 10% of total net exposure and the aggregate of such counterparties was $399 million. Approximately 82% of NRG’s positions relating to credit risk roll-off by the end of 2012. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration. Given the credit quality, diversification and term of the exposure in the portfolio, NRG does not anticipate a material impact on the Company’s financial results from nonperformance by any of NRG’s counterparties.

79

     Retail Customer Credit Risk

     NRG is exposed to retail credit risk through its competitive electricity supply business, which serves C&I and Mass customers in Texas. Retail credit risk results when a customer fails to pay for services rendered. The losses could be incurred from nonpayment of customer accounts receivable and any 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, 2010, the Company’s credit exposure to C&I customers was diversified across many customers and various industries, with a significant portion of the exposure with government entities. NRG is also exposed to credit risk relating to its 1.5 million Mass customers, which may result in a write-off of bad debt. During the quarter, the Company experienced improved customer payment behavior, but current economic conditions may affect the Company’s customers’ ability to pay bills in a timely manner, which could increase customer delinquencies and may lead to an increase in bad debt.

     Certain of the Company’s hedging agreements contain provisions that require the Company to post additional collateral if the counterparty determines that there has been deterioration in credit quality, generally termed “adequate assurance” under the agreements or require the Company to post additional collateral if there was a one notch downgrade in the Company’s credit rating. The collateral required for contracts that have adequate assurance clauses that are in a net liability position as of March 31, 2010, was $42 million. The collateral required for contracts with credit rating contingent features that are in a net liability position as of March 31, 2010, was $16 million. The Company is also a party to certain marginable agreements where NRG has a net liability position but the counterparty has not called for the collateral due, which is approximately $7 million as of March 31, 2010.

  Fair Value of Derivative Instruments

     NRG may enter into long-term power purchase and sales contracts, fuel purchase contracts and other energy-related financial instruments to mitigate variability in earnings due to fluctuations in spot market prices and to hedge fuel requirements at generation facilities. In addition, in order to mitigate interest rate risk associated with the issuance of the Company’s variable rate and fixed rate debt, NRG enters into interest rate swap agreements.

     NRG’s trading activities are subject to limits within the Company’s Risk Management Policy. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings.

     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, 2010, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at March 31, 2010.

Derivative Activity Gains/(Losses)	(In millions)
Fair value of contracts as of December 31, 2009	$	459
Contracts realized or otherwise settled during the period		(33	)
Changes in fair value		480
Fair value of contracts as of March 31, 2010	$	906

	Fair Value of Contracts as of March 31, 2010
	Maturity									Maturity
(In millions)	Less Than			Maturity			Maturity			in Excess			Total Fair
Fair value hierarchy gains/(losses)	1 Year			1-3 Years			4-5 Years			4-5 Years			Value
Level 1	$	(41	)	$	(53	)	$	(30	)	$	—		$	(124	)
Level 2		456			515			113			(29	)		1,055
Level 3		(45	)		9			11			—			(25	)
Total	$	370		$	471		$	94		$	(29	)	$	906

     A small portion of NRG’s contracts are exchange-traded contracts with readily available quoted market prices. The majority 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 the Company’s transactions and the Company believes such price quotes are executable.

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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 represents contracts for which external sources or observable market quotes are not available. These contracts are valued based on various valuation 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. Contracts valued with prices provided by models and other valuation techniques make up 3% of the total fair value of all derivative contracts. 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 after cash collateral paid/received under a specific master agreement is an asset, the Company calculates credit reserve applying the counterparty’s default swap rate. If the net exposure after cash collateral paid/received under a specific master agreement is a liability, the Company calculates credit reserve applying 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, 2010, the credit reserve resulted in a $2 million decrease in fair value which is composed of a $3 million loss in OCI and a $1 million gain in derivative revenue and cost of operations.

     The fair values in each category reflect the level of forward prices and volatility factors as of March 31, 2010, and may change as a result of changes in these factors. Management uses its best estimates to determine the fair value of commodity and derivative contracts NRG holds and sells. These estimates consider various factors including closing exchange and over-the-counter price quotations, time value, volatility factors and credit exposure. It is possible; however, that future market prices could vary from those used in recording assets and liabilities from energy marketing and trading activities and such variations could be material.

     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 Commodity Price Risk, NRG measures the sensitivity of the Company’s portfolio to potential changes in market prices using 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, 2010, NRG’s net derivative asset was $906 million, an increase to total fair value of $447 million as compared to December 31, 2009. This increase was primarily driven by the decreases in gas and power prices and the roll-off of trades that settled during the period.

     Based on a sensitivity analysis, the impact of a $1 per MMBtu increase or decrease in natural gas prices across the term of the derivative contracts would cause a change of approximately $324 million in the net value of derivatives as of March 31, 2010.

  Currency Exchange Risk

     NRG may be subject to foreign currency exchange risk as a result of the Company entering into purchase commitments with foreign vendors for the purchase of major equipment associated with RepoweringNRG initiatives. To reduce the risks to such foreign currency exposure, the Company may enter into transactions to hedge its foreign currency exposure using currency options and forward contracts. As of March 31, 2010, there were no foreign currency options or forward contracts outstanding for purchase commitments. As a result of the Company’s limited foreign currency exposure to date, the effect of foreign currency fluctuations has not been material to the Company’s results of operations, financial position and cash flows as of and for the three months ended March 31, 2010.

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ITEM 4 — CONTROLS AND PROCEDURES

     Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

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

     Changes in Internal Control over Financial Reporting

     There were no changes in the Company’s internal controls over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred in the first quarter 2010 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

     Inherent Limitations over Internal Controls

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

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PART II — OTHER INFORMATION

ITEM 1 — LEGAL PROCEEDINGS

     For a discussion of material legal proceedings in which NRG was involved through March 31, 2010, see Note 15, Commitments and Contingencies, to this Form 10-Q.

ITEM 1A — RISK FACTORS

     Information regarding risk factors appears in Part I, Item 1A, Risk Factors in NRG Energy, Inc.’s Annual Report on Form 10-K for the fiscal year ended December 31, 2009.

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

     None.

ITEM 3 — DEFAULTS UPON SENIOR SECURITIES

     None.

ITEM 4 — (REMOVED AND RESERVED)

ITEM 5 — OTHER INFORMATION

     None.

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ITEM 6 — EXHIBITS

Exhibits
4.1	Twenty-Eighth Supplemental Indenture, dated as of April 16, 2010, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York. (1)
4.2	Twenty-Ninth Supplemental Indenture, dated as of April 16, 2010, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York. (1)
4.3	Thirtieth Supplemental Indenture, dated as of April 16, 2010, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York. (1)
4.4	Thirty-First Supplemental Indenture, dated as of April 16, 2010, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York. (1)
10.1	Project Agreement, Settlement Agreement and Mutual Release, dated March 1, 2010, by and among by and among Nuclear Innovation North America LLC, the City of San Antonio acting by and through the City Public Service Board of San Antonio, a Texas municipal utility, NINA Texas 3 LLC and NINA Texas 4 LLC, and solely for purposes of certain sections of the Settlement Agreement, by NRG Energy, Inc and NRG South Texas LP. (2)
10.2*	STP 3 & 4 Owners Agreement, dated March 1, 2010, by and among Nuclear Innovation North America LLC, the City of San Antonio, NINA Texas 3 LLC and NINA Texas 4 LLC. (2)
10.3	Chief Financial Officer Compensation Table for 2010. (3)
10.4	2009 Executive Change-in-Control and General Severance Plan. (3)
31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
31.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
31.3	Certification of Chief Accounting Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
32	Certification of Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, filed herewith.
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Extension Calculation Linkbase
101.DEF	XBRL Taxonomy Extension Definition Linkbase
101.LAB	XBRL Taxonomy Extension Label Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase

*  Portions of this exhibit have been redacted and are subject to a confidential treatment request filed with the Securities and Exchange Commission pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended.

(1)	Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on April 21, 2010.
(2)	Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on March 2, 2010.
(3)	Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on April 1, 2010

84

SIGNATURES

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

	NRG ENERGY, INC. (Registrant)
By:
	/s/ DAVID W. CRANE
	David W. Crane
	Chief Executive Officer (Principal Executive Officer)
	/s/ GERALD LUTERMAN
	Gerald Luterman
	Chief Financial Officer (Principal Financial Officer)
	/s/ JAMES J. INGOLDSBY
	James J. Ingoldsby
Date: May 10, 2010	Chief Accounting Officer (Principal Accounting Officer)

85

EXHIBIT INDEX

Exhibits
4.1	Twenty-Eighth Supplemental Indenture, dated as of April 16, 2010, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York. (1)
4.2	Twenty-Ninth Supplemental Indenture, dated as of April 16, 2010, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York. (1)
4.3	Thirtieth Supplemental Indenture, dated as of April 16, 2010, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York. (1)
4.4	Thirty-First Supplemental Indenture, dated as of April 16, 2010, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York. (1)
10.1	Project Agreement, Settlement Agreement and Mutual Release, dated March 1, 2010, by and among by and among Nuclear Innovation North America LLC, the City of San Antonio acting by and through the City Public Service Board of San Antonio, a Texas municipal utility, NINA Texas 3 LLC and NINA Texas 4 LLC, and solely for purposes of certain sections of the Settlement Agreement, by NRG Energy, Inc and NRG South Texas LP. (2)
10.2*	STP 3 & 4 Owners Agreement, dated March 1, 2010, by and among Nuclear Innovation North America LLC, the City of San Antonio, NINA Texas 3 LLC and NINA Texas 4 LLC. (2)
10.3	Chief Financial Officer Compensation Table for 2010. (3)
10.4	2009 Executive Change-in-Control and General Severance Plan. (3)
31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
31.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
31.3	Certification of Chief Accounting Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
32	Certification of Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, filed herewith.
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Extension Calculation Linkbase
101.DEF	XBRL Taxonomy Extension Definition Linkbase
101.LAB	XBRL Taxonomy Extension Label Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase

*  Portions of this exhibit have been redacted and are subject to a confidential treatment request filed with the Securities and Exchange Commission pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended.

(1)	Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on April 21, 2010.
(2)	Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on March 2, 2010.
(3)	Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on April 1, 2010.

86

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, David W. Crane, certify that:

1. I have reviewed this quarterly report on Form 10-Q of NRG Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

	/s/ DAVID W. CRANE
	David W. Crane
Date: May 10, 2010	Chief Executive Officer (Principal Executive Officer)

87

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Gerald Luterman, certify that:

1. I have reviewed this quarterly report on Form 10-Q of NRG Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

	/s/ GERALD LUTERMAN
	Gerald Luterman
Date: May 10, 2010	Chief Financial Officer (Principal Financial Officer)

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EX-31.3

EXHIBIT 31.3

CERTIFICATION

I, James J. Ingoldsby, certify that:

1. I have reviewed this quarterly report on Form 10-Q of NRG Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

	/s/ JAMES J. INGOLDSBY
	James J. Ingoldsby
Date: May 10, 2010	Chief Accounting Officer (Principal Accounting Officer)

89

EX-32

EXHIBIT 32

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

     In connection with the Quarterly Report of NRG Energy, Inc. on Form 10-Q for the quarter ended March 31, 2010, as filed with the Securities and Exchange Commission on the date hereof (the “Form 10-Q”), each of the undersigned officers of the Company certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge:

     (1) The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

     (2) The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company as of the dates and for the periods expressed in the Form 10-Q.

Date: May 10, 2010

/s/ DAVID W. CRANE  

David W. Crane, 

Chief Executive Officer
(Principal Executive Officer) 

/s/ GERALD LUTERMAN  

Gerald Luterman, 

Chief Financial Officer
(Principal Financial Officer) 

/s/ JAMES J. INGOLDSBY  

James J. Ingoldsby, 

Chief Accounting Officer
(Principal Accounting Officer) 

     The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.

     A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to NRG Energy, Inc. and will be retained by NRG Energy, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

90