Edgar Filing: NRG ENERGY, INC.

The acquisition of WCP on March 31, 2006, operating income during the first quarter 2007 increased by $6 million from —

A $10 million increase due to inclusion of WCP results that include the favorable impact from the new tolling agreements at the Encina and El Segundo plants.

Offset by $4 million of expenses related to development costs for the regions repowering projects and G&A corporate allocations.

The sale of Red Bluff and Chowchilla II plants on January 3, 2007 — during the three months ended March 31, 2006, these operations generated an operating loss of $2 million.

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

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

	For the quarterly period ended: March 31, 2007	Commission File Number: 001-15891

NRG Energy, Inc.
(Exact name of Registrant as specified in its charter)


Delaware (State or other jurisdiction of incorporation or organization)		41-1724239 (I.R.S. Employer Identification No.)


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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such 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 is a large accelerated filer, an accelerated filer or a non-accelerated filer (as defined in Rule 12 b-2 of the Exchange Act).

Large accelerated filer þ Accelerated filer o Non-accelerated filer o

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 Section 12, 13 or 15 (d) of the Securities and Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.

Yes þ No o

As of April 27, 2007, there were 121,158,437 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
Item 1 — Condensed Consolidated Financial Statements and Notes			6
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS			6
CONDENSED CONSOLIDATED BALANCE SHEETS			7
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS			8
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS			9
Item 2 — Management’s Discussion and Analysis of Financial Condition and Results of Operations			32
Item 3 — Quantitative and Qualitative Disclosures About Market Risk			52
Item 4 — Controls and Procedures			55
PART II — OTHER INFORMATION			56
Item 1 — Legal Proceedings			56
Item 1A — Risk Factors			56
Item 2 — Unregistered Sales of Equity Securities and Use of Proceeds			56
Item 3 — Defaults Upon Senior Securities			56
Item 4 — Submission of Matters to a Vote of Security Holders			56
Item 5 — Other Information			56
Item 6 — Exhibits			57
EX-10.1: AMENDED AND RESTATED LONG TERM INCENTIVE PLAN
EX-10.2: EXECUTIVE AND KEY MANAGEMENT CHANGE-IN-CONTROL AND GENERAL SEVERANCE AGREEMENT
EX-31.1: CERTIFICATION
EX-31.2: CERTIFICATION
EX-31.3: CERTIFICATION
EX-32: CERTIFICATION

CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION

This Quarterly Report on Form 10-Q includes forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. The words “believes”, “projects”, “anticipates”, “plans”, “expects”, “intends”, “estimates” and similar expressions are intended to identify forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors 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 Related to NRG in Part II, Item 1A, of the Company’s Annual Report on Form 10-K and the following:

	•		General economic conditions, changes in the wholesale power markets and fluctuations in the cost of fuel;
	•		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 (including general and administrative expenses), and generate earnings and cash flows from its asset-based businesses in relation to its debt and other obligations;
	•		NRG’s potential inability 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;
	•		Price mitigation strategies and other market structures employed by independent system operators, or ISOs, or regional transmission organizations, 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 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; and
	•		NRG’s ability to implement its RepoweringNRG strategy of developing and building new power generation facilities, including new nuclear units and IGCC units.
	•		NRG’s ability to consummate or achieve the expected benefits of the Comprehensive Capital Allocation Plan as described in this quarterly report.

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

GLOSSARY OF TERMS

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


Acquisition		February 2, 2006 acquisition of Texas Genco LLC, now referred to as the Company’s Texas region
ARO		Asset Retirement Obligation
BACT		Best Available Control Technology
Baseload capacity		Electric power generation capacity normally expected to serve loads on an around-the-clock basis throughout the calendar year
BTA		Best Technology Available
BTU		British Thermal Unit
CAA		Clean Air Act
CAIR		Clean Air Interstate Rule
CAISO		California Independent System Operator
CAMR		Clean Air Mercury Rule
Capital Allocation Program		Share repurchase program entered into in August 2006
Capacity factor		The ratio of the actual net electricity generated to the energy that could have been generated at continuous full-power operation during the year
Comprehensive Capital Allocation Plan		A comprehensive plan to support and facilitate the Company’s capital allocation strategy that includes a holding company structure to enable the distribution of cash dividend on the Company’s common stock, the pay down of debt, a stock split, and the Capital Allocation Program
CDWR		California Department of Water Resources
CL&P		Connecticut Light & Power
CO₂		Carbon dioxide
CPUC		California Public Utilities Commission
DNREC		Delaware Department of Natural Resources and Environmental Control
EFOR		Equivalent Forced Outage Rates — considers the equivalent impact that forced de-ratings have in addition to full forced outages
EITF		Emerging Issues Task Force
EITF 02-3		EITF Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities”
EPC		Engineering, Procurement and Construction
ERCOT		Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas
FASB		Financial Accounting Standards Board, the designated organization for establishing standards for financial accounting and reporting
FCM		Forward Capacity Market
FERC		Federal Energy Regulatory Commission
FIN		FASB Interpretation
GHG		Greenhouse Gases
Hedge Reset		Net settlement of long-term power contracts and gas swaps by negotiating prices to current market completed in November 2006
IGCC		Integrated Gasification Combined Cycle
ISO		Independent System Operator, also referred to as Regional Transmission Organization, or RTO
ISO-NE		ISO New England, Inc.
ITISA		Itiquira Energetica S.A.
kW		Kilowatts
KWh		Kilowatt-hours
Letter of Credit Facility		NRG’s $1.5 billion senior secured synthetic letter of credit facility which matures on February 1, 2013
LFRM		Locational Forward Reserve Market
LIBOR		London Inter-Bank Offered Rate
Merit Order		A term used for the ranking of power stations in terms of increasing order of fuel costs.
MMBtu		Million British Thermal Units
MW		Megawatts
MWh		Saleable megawatt hours net of internal/parasitic load megawatt-hours
NEPOOL		New England Power Pool
New York Rest of State		New York State excluding New York City

GLOSSARY OF TERMS — cont’d


NiMo		Niagara Mohawk Power Corporation
NO_x		Nitrogen oxide
NOL		Net Operating Loss
NOV		Notice of Violation
NPNS		Normal Purchase Normal Sale
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
PMI		NRG Power Marketing, Inc., a wholly-owned subsidiary of NRG which procures transportation and fuel for the Company’s generation facilities, sells the power from these facilities, and manages all commodity trading and hedging for NRG
Powder River Basin, or PRB, Coal		Coal produced in the northeastern Wyoming and southeastern Montana, which has low sulfur content
PPA		Power Purchase Agreement
PSD		Prevention of Significant Deterioration
PUSH		Peaking Unit Safe Harbor
RepoweringNRG		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.
Revolving Credit Facility		NRG’s $1 billion senior secured credit facility which matures on February 2, 2011
RMR		Reliability Must-Run
RTO		Regional Transmission Organization, also referred to as an ISO
Sarbanes-Oxley		Sarbanes-Oxley Act of 2002
SEC		United States Securities and Exchange Commission
Senior Credit Facility		NRG’s senior secured facility, which is comprised of a $3.1 billion Term B loan facility which matures on February 1, 2013, its $1.5 billion Letter of Credit Facility, and its $1 billion Revolving Credit Facility
SERC		Southeastern Electric Reliability Council/ Entergy
SFAS		Statement of Financial Accounting Standards issued by the FASB
SFAS 71		SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation”
SFAS 109		SFAS No. 109, “Accounting for Income Taxes”
SFAS 123		SFAS No. 123, “Accounting for Stock-Based Compensation”
SFAS 123R		SFAS No. 123 (revised 2004), “Share-Based Payment”
SFAS 133		SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS 142		SFAS No. 142, “Goodwill and Other Intangible Assets”
SFAS 144		SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”
SFAS 158		SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R)”
SO₂		Sulfur dioxide
SOP		Statement of Position issued by the American Institute of Certified Public Accountants
SOP 90-7		Statement of Position 90-7 “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code”
STP		South Texas Project — Nuclear generating facility located near Bay City, Texas in which NRG owns a 44% interest
Texas Genco		Texas Genco LLC, now referred to as the Company’s Texas region
Uprate		A sustainable increase in the electrical rating of a generating facility
US		United States of America
USEPA		United States Environmental Protection Agency
U.S. GAAP		Accounting principles generally accepted in the United States
VAR		Value at Risk
WCP		West Coast Power (Generation) Holdings, LLC

PART I — FINANCIAL INFORMATION

ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


(In millions except per share amounts)
Three months ended March 31,	2007			2006

Operating Revenues
Total operating revenues	$	1,310		$	1,043

Operating Costs and Expenses
Cost of operations		784			659
Depreciation and amortization		161			118
General and administrative		86			57
Development costs		23			—

Total operating costs and expenses		1,054			834
Gain on sale of assets		17			—

Operating Income		273			209

Other Income/(Expense)
Equity in earnings of unconsolidated affiliates		13			21
Write down of equity method investments		—			(3	)
Other income, net		16			80
Refinancing expenses		—			(178	)
Interest expense		(181	)		(115	)

Total other expenses		(152	)		(195	)

Income From Continuing Operations Before Income Taxes		121			14
Income tax expense/(benefit)		56			(1	)

Income From Continuing Operations		65			15
Income on Discontinued Operations, net of Income Taxes		—			11

Net Income	$	65		$	26
Preference stock dividends		14			10

Income Available for Common Stockholders	$	51		$	16

Weighted Average Number of Common Shares Outstanding — Basic		122			117
Income From Continuing Operations per Weighted Average Common Share — Basic	$	0.42		$	0.04
Income From Discontinued Operations per Weighted Average Common Share — Basic		—			0.09
Net Income per Weighted Average Common Share — Basic	$	0.42		$	0.13
Weighted Average Number of Common Shares Outstanding —Diluted		135			119
Income From Continuing Operations per Weighted Average Common Share — Diluted	$	0.41		$	0.04
Income From Discontinued Operations per Weighted Average Common Share — Diluted		—			0.09
Net Income per Weighted Average Common Share — Diluted	$	0.41		$	0.13

See notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


	March 31, 2007			December 31, 2006
(in millions, except shares and par value)	(unaudited)

ASSETS
Current Assets
Cash and cash equivalents	$	655		$	795
Restricted cash		49			44
Accounts receivable, less allowance for doubtful accounts of $1 and $1		409			372
Inventory		400			421
Derivative instruments valuation		854			1,230
Deferred income taxes		43			—
Prepayments and other current assets		259			221

Total current assets		2,669			3,083

Property, plant and equipment, net of accumulated depreciation of $1,159 and $984		11,521			11,600

Other Assets
Equity investments in affiliates		361			344
Notes receivable and capital lease, less current portion		476			479
Goodwill		1,787			1,789
Intangible assets, net of accumulated amortization of $292 and $259		958			981
Nuclear decommissioning trust fund		357			352
Derivative instruments valuation		187			439
Deferred income taxes		27			27
Other non-current assets		256			262
Intangible assets held-for-sale		112			79

Total other assets		4,521			4,752

Total Assets	$	18,711		$	19,435

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	129		$	130
Accounts payable		295			332
Derivative instruments valuation		824			964
Deferred income taxes		—			164
Accrued expenses and other current liabilities		320			442

Total current liabilities		1,568			2,032

Other Liabilities
Long-term debt and capital leases		8,637			8,647
Nuclear decommissioning reserve		280			289
Nuclear decommissioning trust liability		335			324
Deferred income taxes		623			554
Derivative instruments valuation		418			351
Out-of-market contracts		839			897
Other non-current liabilities		437			435

Total non-current liabilities		11,569			11,497

Total Liabilities		13,137			13,529

Minority Interest		1			1
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)		892			892
Common Stock		1			1
Additional paid-in capital		4,469			4,476
Retained earnings		790			739
Less treasury stock, at cost — 16,300,581 and 14,800,581 shares		(835	)		(732	)
Accumulated other comprehensive income		9			282

Total Stockholders’ Equity		5,326			5,658

Total Liabilities and Stockholders’ Equity	$	18,711		$	19,435

See notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


(In millions)
Three months ended March 31,	2007			2006

Cash Flows from Operating Activities
Net income	$	65		$	26
Adjustments to reconcile net income to net cash provided by operating activities
Distributions less than equity in earnings of unconsolidated affiliates		(10	)		(12	)
Depreciation and amortization of nuclear fuel		174			125
Amortization and write-off of financing costs and debt discount/premiums		9			57
Amortization of intangibles and out-of-market contracts		(29	)		9
Changes in deferred income taxes		47			46
Changes in nuclear decommissioning trust liability		9			(3	)
Changes in derivatives		90			(21	)
Changes in collateral deposits supporting energy risk management activities		(120	)		230
Gain on sale of assets		(17	)		—
Gain on legal settlement		—			(67	)
Gain on sale of discontinued operations		—			(10	)
Gain on sale of emission allowances		(5	)		(59	)
Amortization of unearned equity compensation		7			3
Write down of equity method investments		—			3
Cash provided/(used) by changes in other working capital, net of acquisition and disposition affects		(114	)		15

Net Cash Provided by Operating Activities		106			342

Cash Flows from Investing Activities
Acquisition of Texas Genco LLC, net of cash acquired		—			(4,263	)
Acquisition of WCP, net of cash acquired		—			(25	)
Capital expenditures		(107	)		(35	)
Increase in restricted cash, net		(5	)		(3	)
Decrease in notes receivable		9			8
Purchases of emission allowances		(61	)		(15	)
Proceeds from sale of emission allowances		32			68
Investments in nuclear decommissioning trust fund securities		(68	)		(42	)
Proceeds from sales of nuclear decommissioning trust fund securities		59			45
Proceeds from sale of assets		29			—
Proceeds from sale of investments		—			45
Proceeds from sale of discontinued operations		—			15

Net Cash Used by Investing Activities		(112	)		(4,202	)

Cash Flows from Financing Activities
Payment of dividends to preferred stockholders		(14	)		(10	)
Payment of financing element of acquired derivatives		—			(29	)
Payment for treasury stock		(103	)		—
Funded letter of credit		—			350
Proceeds from issuance of common stock, net of issuance costs		—			986
Proceeds from issuance of preferred shares, net of issuance costs		—			486
Proceeds from issuance of long-term debt		—			7,175
Payment of deferred debt issuance costs		—			(164	)
Payments for short and long-term debt		(19	)		(4,623	)

Net Cash Provided/(Used) by Financing Activities		(136	)		4,171

Change in Cash from Discontinued Operations		—			(17	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents		2			1

Net Increase/(Decrease) in Cash and Cash Equivalents		(140	)		295
Cash and Cash Equivalents at Beginning of Period		795			493

Cash and Cash Equivalents at End of Period	$	655		$	788

See notes to condensed consolidated financial statements.

NRG ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 — Basis of Presentation

NRG Energy, Inc., or NRG or the Company, is a wholesale power generation company with a significant presence in major competitive power markets in the United States. NRG is primarily engaged in the ownership, development, construction and operation of power generation facilities, the transacting in and trading of fuel and transportation services, and the trading of energy, capacity and related products in the United States and internationally.

The accompanying unaudited interim consolidated financial statements have been prepared in accordance with the Securities and Exchange Commission’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 accounting policies NRG follows are set forth in Note 2 to the Company’s financial statements in its Annual Report on Form 10-K for the year ended December 31, 2006. The following notes should be read in conjunction with such policies and other disclosures in the Form 10-K. Interim results are not necessarily indicative of results for a full year.

In the opinion of management, the accompanying unaudited interim 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, 2007, and the results of operations and cash flows for the three months ended March 31, 2007 and 2006. Certain prior-year amounts have been reclassified for comparative purposes.

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.

Recent Accounting Developments

In July 2006, the FASB issued FASB Interpretation Number 48, Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109, or FIN 48, which applies to all tax positions related to income taxes subject to SFAS 109. FIN 48 requires a new evaluation process for all tax positions taken, recognizing tax benefits when it is more-likely-than-not that a tax position will be sustained upon examination by the authorities. The benefit from a position that has surpassed the more-likely-than-not threshold is the largest amount of benefit that is more than 50% likely to be realized upon settlement. Differences between the amounts recognized in the statement of financial position prior to the adoption of FIN 48 and the amounts reported after adoption are to be accounted for as an adjustment to the beginning balance of retained earnings. Subsequently, any such differences will be recorded as a charge to income tax expense. The Company recognizes interest and penalties accrued related to unrecognized tax benefits as a component of income tax expense. As of March 31, 2007, the Company had completed its evaluation of the impact of the January 1, 2007, adoption of FIN 48 and has determined that such adoption will not have a material impact on the Company’s financial position, results of operations and cash flows.

Note 2 — Comprehensive Income

The following table summarizes the components of the Company’s comprehensive income for the three months ended March 31, 2007 and 2006.


(In millions)
Three months ended March 31,	2007			2006

Net income	$	65		$	26
Changes in derivative activity, net of tax		(283	)		247
Foreign currency translation adjustment		10			3

Other comprehensive income, net of tax		(273	)		250

Comprehensive income/(loss)	$	(208	)	$	276

The following table summarizes the changes in the Company’s accumulated other comprehensive income for the three months ended March 31, 2007:


(In millions)
As of March 31,	2007

Accumulated other comprehensive income as of December 31, 2006	$	282
Changes in derivative activity, net of tax		(283	)
Foreign currency translation adjustments		10

Accumulated other comprehensive income as of March 31, 2007	$	9

Note 3 — Business Acquisitions and Dispositions

Acquisition of Remaining 50% interest in WCP

On March 31, 2006, NRG completed purchase and sale agreements for projects co-owned with Dynegy, Inc. Under the agreements, NRG acquired Dynegy’s 50% ownership interest in WCP (Generation) Holdings, LLC., or WCP, for $205 million in cash and the assumption of a $1 million liability, with NRG becoming the sole owner of WCP’s 1,825 MW of generation capacity in Southern California. In addition, NRG sold to Dynegy the Company’s 50% ownership interest in Rocky Road Power LLC, or Rocky Road, a 330 MW gas-fueled, simple cycle peaking plant located in Dundee, Illinois. NRG sold Rocky Road for a fair value sale price of $45 million, paying Dynegy a net purchase price of $160 million at closing. Prior to the purchase, NRG had an existing investment in WCP accounted for as an equity method investment, or Original Investment.

The acquisition of the remaining 50% interest in WCP, or New Investment, was accounted for as a step acquisition since the Original Investment was transacted in a prior period. As a result, the value of the Original Investment and the purchase price of the New Investment were determined and allocated separately. The value of the Original Investment was based on the book value of approximately $159 million as of the date of the acquisition of the New Investment.

The value of the New Investment was allocated based on the fair value of assets acquired and liabilities assumed as of March 31, 2006. The purchase price allocation reflected an excess of fair value of the net assets acquired over the purchase price of the New Investment, resulting in negative goodwill of approximately $48 million. The negative goodwill was subsequently allocated as a reduction to the fair value of WCP’s fixed assets.

The following summarizes the purchase price and allocation impact of the WCP acquisition as of March 31, 2006:


				New Investment
				Fair Value before						Fair Value after
	Original			Negative Goodwill			Allocation of			Negative Goodwill
(in millions)	Investment			Allocation			Negative Goodwill			Allocation			Purchase Price Allocation

Current assets	$	149		$	153		$	—		$	153		$	302
Property, plant and equipment		24			103			(38	)		65			89
Intangible assets		2			26			(10	)		16			18
Other non-current assets		—			9			—			9			9
Current liabilities		(13	)		(18	)		—			(18	)		(31	)
Non-current liabilities		(3	)		(19	)		—			(19	)		(22	)
Negative goodwill		—			(48	)		48			—			—

Total Equity	$	159		$	206		$	—		$	206		$	365

Other Business Events

Red Bluff and Chowchilla — On January 3, 2007, NRG completed the sale of the Company’s Red Bluff and Chowchilla II power plants to an entity controlled by Wayzata Investment Partners LLC. These power plants, located in California, are fueled by natural gas, with generating capacity of 45 MW and 49 MW, respectively. The sale resulted in a pre-tax gain of approximately $18 million.

Note 4 — Discontinued Operations

NRG has classified material business operations and gains/losses recognized on sale, as discontinued operations for projects that were sold or have met the required criteria for such classification. The financial results for the affected businesses have been

accounted for as discontinued operations. Accordingly, prior periods have been recast to report the operations as discontinued. NRG classifies certain assets as held-for-sale when management has committed to selling certain long lived assets within the next year. This classification does not affect prior period operating results.

For the three months ended March 31, 2006, discontinued operations consisted of the results related to the Company’s Audrain, Flinders and Resource Recovery operations. NRG had no assets classified as discontinued operations for the three months ended March 31, 2007.

Summarized results of operations of the Company’s discontinued operations were as follows:


(In millions)
Three months ended March 31,	2007		2006

Operating revenues	$	—	$	68
Pre-tax income from operations of discontinued components		—		2
Income from discontinued operations, net of income taxes	$	—	$	11

Note 5 — Accounting for Derivative Instruments and Hedging Activities

SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, or SFAS 133, 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 Normal Purchase Normal Sale, or 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 OCI and subsequently recognize in earnings when the hedged transaction occurs. The ineffective portion of a cash flow hedge is immediately recognized in earnings.

Accumulated Other Comprehensive Income

The following table summarizes the effects of SFAS 133 on NRG’s OCI balance attributable to hedged derivatives for the three months ended March 31, 2007, net of tax:


	Energy			Interest
(In millions)	Commodities			Rate			Total

Accumulated OCI balance at December 31, 2006	$	193		$	16		$	209
Realized from OCI during the period:
— Due to realization of previously deferred amounts		(17	)		—			(17	)
Mark-to-market of hedge contracts		(259	)		(7	)		(266	)

Accumulated OCI balance at March 31, 2007	$	(83	)	$	9		$	(74	)

Losses expected to be realized from OCI during the next 12 months	$	4		$	—		$	4

The following table summarizes the effects of SFAS 133 on NRG’s OCI balance attributable to hedged derivatives for the three months ended March 31, 2006, net of tax:


	Energy			Interest
(In millions)	Commodities			Rate			Total

Accumulated OCI balance at December 31, 2005	$	(204	)	$	8		$	(196	)
Realized from OCI during the period:
— Due to realization of previously deferred amounts		20			(2	)		18
Mark-to-market of hedge contracts		187			42			229

Accumulated OCI balance at March 31, 2006	$	3		$	48		$	51

As of March 31, 2007, the net balance in OCI relating to SFAS 133 was an unrecognized loss of approximately $74 million, which is net of $50 million in income taxes. NRG expects $4 million of net deferred losses on derivative instruments accumulated in OCI to be recognized in earnings during the next twelve months.

Statement of Operations

In accordance with SFAS 133, unrealized gains and losses associated with changes in the fair value of derivative instruments not accounted for as hedge derivatives and ineffectiveness of hedge derivatives are reflected in current period earnings.

The following tables summarizes the pre-tax effects of non-hedge derivatives, derivatives that do not qualify as hedges, and ineffectiveness of hedge derivatives on NRG’s statement of operations for the three months ended March 31, 2007:


	Energy
(In millions)	Commodities			Interest Rate		Total

Operating Revenues	$	(90	)	$	—	$	(90	)
Equity in earnings of unconsolidated subsidiaries		—			—		—
Cost of operations		—			—		—
Interest Expense		—			—		—

Total statement of operations impact before tax	$	(90	)	$	—	$	(90	)


	Energy
(In millions)	Commodities		Interest Rate			Total

Operating Revenues	$	49	$	—		$	49
Equity in earnings of unconsolidated subsidiaries		—		—			—
Cost of operations		—		—			—
Interest expense		—		3			3

Total statement of operations impact before tax	$	49	$	(3	)	$	46

For the three months ended March 31, 2007, the unrealized loss associated with changes in the fair value of derivative instruments not accounted for as hedge derivatives of $90 million is comprised of $79 million of fair value decreases in forward sales of electricity and fuel, a $44 million gain due to the ineffectiveness associated with financial forward contracted electric and gas sales, $70 million from the reversal of mark-to-market gains which ultimately settled as financial revenues of which $57 million was related to economic hedges and $13 million was related to trading activity. In addition, the Company recorded $15 million of gains associated with open positions also related to trading activity.

For the three months ended March 31, 2006, the unrealized gain associated with changes in the fair value of derivative instruments not accounted for as hedge derivatives of $49 million is comprised of $37 million of fair value increases in forward sales of electricity and fuel, an $8 million loss due to the ineffectiveness associated with financial forward contracted electric and gas sales, $21 million from the reversal of mark-to-market losses which ultimately settled as financial revenues, of which $45 million was related to losses on economic hedges and $24 million was related to gains on trading activity. In addition, the Company recorded $1 million of losses associated with open positions also related to trading activity. NRG’s pre-tax earnings were also affected by a $3 million loss due to ineffectiveness associated with the Company’s fixed-to-floating interest rate swap designated as a hedge of fair value changes in the Senior Notes.

Note 6 — 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, 2007 and 2006:


	Authorized		Issued		Treasury			Outstanding

Balance as of December 31, 2006		500,000,000		137,124,132		(14,800,581	)		122,323,551
Capital Allocation Program — Phase II during the first quarter 2007		—		—		(1,500,000	)		(1,500,000	)
Shares issued from LTIP through March 31, 2007		—		299,457		—			299,457

Balance as of March 31, 2007		500,000,000		137,423,589		(16,300,581	)		121,123,008


Balance as of December 31, 2005		500,000,000		100,048,676		(19,346,788	)		80,701,888
Shares issued January 2006		—		20,855,057		—			20,855,057
Acquisition of Texas Genco LLC		—		16,059,504		19,346,788			35,406,292
Shares issued from LTIP through March 31, 2006		—		12,038		—			12,038

Balance as of March 31, 2006		500,000,000		136,975,275		—			136,975,275

Common Stock

NRG’s authorized common stock consists of 500 million shares of NRG stock. Common stock issued as of March 31, 2007 and 2006 was 137,423,589 and 136,975,275 shares, respectively.

Treasury Stock

In 2006, NRG initiated a Capital Allocation Program executed in two phases. Phase I was completed in the fourth quarter 2006, with the repurchase of 10,587,700 shares of the Company’s common stock for approximately $500 million. Phase II is also a $500 million share buyback program that began in the fourth quarter 2006 with the repurchase of 4,212,881 shares of NRG common stock for a total of approximately $232 million. During the first quarter 2007, NRG repurchased an additional 1,500,000 shares of the Company’s common stock for approximately $103 million. As of March 31, 2007, NRG had repurchased a total of 16,300,581 shares of its common stock at a cost of approximately $835 million as part of its Capital Allocation Program. The Company expects to complete Phase II of the Capital Allocation Program in 2007 with the repurchase of approximately an additional $165 million of NRG common stock.

As part of Phase I of the Capital Allocation Program, NRG issued Notes and Preferred Interests to Credit Suisse which included an embedded derivative that NRG may choose to pay in cash or stock. At maturity, should NRG’s stock price exceed a compound annual growth rate of 20% beyond the volume-weighted average share price at the time of repurchase, referred to as the Reference Price, NRG will pay to Credit Suisse the excess of NRG’s stock price over the Reference Price. As of March 31, 2007, per the noted calculation, the amount owed to Credit Suisse was approximately $24 million.

Stock Dividend

On April 25, 2007, NRG’s Board of Directors approved a two-for-one stock split of the Company’s outstanding shares of common stock to be effected in the form of stock dividend. The stock split will entitle each stockholder of record at the close of business on May 22, 2007 to receive one additional share for every outstanding share of common stock held. The additional shares resulting from the stock split are expected to be distributed by the Company’s transfer agent on or about May 31, 2007. Upon the completion of the stock split, NRG will have approximately 242 million shares of common stock outstanding.

Note 7 — Equity Compensation

Stock Options, or NQSO’s

The following table summarizes the change in the outstanding NQSO during the three months ended March 31, 2007:


				Weighted Average		Weighted Average Grant-Date
	Shares			Exercise Price		Fair Value Per Share

Outstanding as of December 31, 2006		1,705,536		$	35.18	$	13.40
Granted		368,600			55.83		16.36
Forfeited		(25,401	)		49.76		15.01
Exercised		(37,393	)		43.29		13.45

Outstanding at March 31, 2007		2,011,342			38.63		13.92
Exercisable at March 31, 2007		1,037,003		$	27.74	$	12.74

Restricted Stock Units, or RSU’s

The following table shows the change in the outstanding RSU balance during the three months ended March 31, 2007:


				Weighted Average Grant-Date
Non-vested Shares	Shares			Fair Value Per Share

Non-vested as of December 31, 2006		1,138,593		$	31.48
Granted		44,700			55.83
Vested		(475,350	)		19.99
Forfeited		(17,550	)		37.25

Outstanding as of March 31, 2007		690,393		$	40.78

Performance Units, or PU’s

The following table shows the change in the outstanding PU balance during the three months ended March 31, 2007:


				Weighted Average Grant-Date
Non-vested Shares	Shares			Fair Value Per Share

Non-vested as of December 31, 2006		205,332		$	34.49
Granted		88,800			35.00
Vested		—			—
Forfeited		(8,500	)		33.12

Outstanding as of March 31, 2007		285,632		$	34.69

Note 8 — Earnings Per Share

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

The reconciliation of basic earnings per common share to diluted earnings per share is as follows:


(In millions, except per share data)
Three months ended March 31,	2007			2006

*Basic earnings per share*
Numerator:
Income from continuing operations	$	65		$	15
Preferred stock dividends		(14	)		(11	)

Net income available to common stockholders from continuing operations		51			4
Discontinued operations, net of income tax expense		—			11

Net income available to common stockholders	$	51		$	15

Denominator:
Weighted average number of common shares outstanding		122.0			117.4
*Basic earnings per share:*
Income from continuing operations	$	0.42		$	0.04
Discontinued operations, net of income tax expense		—			0.09

Net income	$	0.42		$	0.13

*Diluted earnings per share*
Numerator:
Net income available to common stockholders from continuing operations	$	51		$	4
Add preferred stock dividends for dilutive preferred stock		4			—

Adjusted income from continuing operations		55			4
Discontinued operations, net of tax		—			11

Net income available to common stockholders	$	55		$	15

*Denominator:*
Weighted average number of common shares outstanding		122.0			117.4
Incremental shares attributable to the issuance of equity compensation (treasury stock method)		1.6			1.4
Incremental shares attributable to embedded derivatives of certain financial instruments (if-converted method)		1.2			—
Incremental shares attributable to assumed conversion features of outstanding preferred stock (if-converted method)		10.5			—

Total dilutive shares		135.3			118.8
*Diluted earnings per share:*
Income from continuing operations	$	0.41		$	0.04
Income from discontinued operations, net of tax		—			0.09

Net income	$	0.41		$	0.13

Effects on Earnings per Share

Stock Awards

Non-Qualified Stock Options — For the three months ended March 31, 2007, none of the Company’s stock options were anti-dilutive. For the three months ended March 31, 2006, options to purchase 595,121 shares of common stock were not included in the computation of diluted earnings per share because the exercise price of the options was greater than the average market price of the

common stock for the respective periods, and therefore the effect would have been anti-dilutive.

Performance Units — For the three months ended March 31, 2007 and 2006, performance units of 252,332 and 206,332, respectively, were not included in the computation of diluted earnings per share because the average market price of NRG’s common stock was less than the target price of the outstanding performance units, and therefore the effect would have been anti-dilutive.

Preferred Stock

5.75% Preferred Stock — For the three months ended March 31, 2007 and 2006, the shares of common stock associated with the 5.75% Preferred Stock were not included in the diluted earnings per share computation since its effect would have been anti-dilutive.

4% Preferred Stock — For the three months ended March 31, 2007, 10,500,000 shares of common stock associated with the 4% Preferred Stock were included in diluted earnings per share. For the three months ended March 31, 2006, the shares of common stock associated with the 4% Preferred Stock were not included in the diluted earnings per share computation since its effect would have been anti-dilutive.

3.625% Preferred Stock — The Company’s 3.625% Preferred Stock contains an embedded derivative which allows for additional cash or common shares to be issued if the average stock price for a 20-day period prior to redemption exceeds $59.08 — the market price trigger. For the three months ended March 31, 2007, the dilutive effect of the embedded derivative included in diluted earnings per share was 773,607 shares of common stock. For the three months ended March 31, 2006 calculation of diluted earnings per share was not impacted by this derivative because the market price trigger was higher than the average market price of NRG’s common stock, and therefore its effect would have been anti-dilutive.

Notes and Preferred Interests — As part of Phase I of the Capital Allocation Program, NRG issued Notes and Preferred Interests to Credit Suisse which included an embedded derivative that NRG may choose to pay in cash or stock. At maturity, should NRG’s stock price exceed a compound annual growth rate of 20% beyond the volume-weighted average share price at the time of repurchase, referred to as the Reference Price, NRG will pay to Credit Suisse the excess of NRG’s stock price over the Reference Price. The value of this excess is considered dilutive for purposes of earnings per share. As of March 31, 2007, NRG’s stock price exceeded the Reference Price creating a dilutive effect of 385,286 shares.

Pro forma Earnings Per Share

As discussed in Note 6, Changes in Capital Structure, on April 25, 2007, the Company’s Board of Directors approved a two-for-one stock split of the Company’s outstanding common stock to be effected in the form of a stock dividend, payable on or about May 31, 2007 to stockholders of record on May 22, 2007. Once the split becomes effective, future presentation of earnings per share will be retroactively recast for all prior periods. Taking into account the effect of the split, basic and diluted earnings per share for the three months ended March 31, 2007, would have been $0.21 and $0.20, respectively. Taking into account the effect of the split, basic and diluted earnings per share for the three months ended March 31, 2006, would have been $0.06 and $0.06, respectively.

Note 9 — Segment Reporting

The Company’s segment structure reflects NRG’s core areas of operation which are primarily the geographic regions of the Company’s wholesale power generation, thermal and chilled water business, and corporate activities. Within NRG’s wholesale power generation operations, there are distinct components with separate operating results and management structures for the following regions: Texas, Northeast, South Central, West and International. All prior period information has been restated to reflect the change in the Company’s segment structure as discussed in Note 17, Segment Reporting, to the Company’s financial statements in its Annual Report on Form 10-K for the year ended December 31, 2006.


	Wholesale Power Generation
(in millions)					South
Three months ended March 31, 2007	Texas		Northeast		Central		West			International		Thermal		Corporate			Elimination			Total


Operating revenues	$	695	$	342	$	151	$	28		$	43	$	49	$	5		$	(3	)	$	1,310
Depreciation and amortization		114		25		17		—			1		3		1			—			161
Equity in earnings of unconsolidated affiliates		—		—		—		(2	)		15		—		—			—			13
Income/(loss) from continuing operations before income taxes		113		38		10		5			24		23		(92	)		—			121

Net income/(loss)	$	60	$	38	$	10	$	5		$	17	$	23	$	(88	)	$	—		$	65

Total assets	$	12,731	$	1,561	$	1,014	$	185		$	1,028	$	222	$	11,510		$	(9,540	)	$	18,711


	Wholesale Power Generation
(in millions)						South
Three months ended March 31, 2006	Texas ^(a)			Northeast		Central		West ^(b)			International		Thermal		Corporate			Elimination			Total


Operating revenues	$	406		$	392	$	172	$	1		$	42	$	42	$	8		$	(20	)	$	1,043
Depreciation and amortization		74			22		16		—			1		3		2			—			118
Equity in earnings of unconsolidated affiliates		—			—		—		(2	)		21		—		2			—			21
Income/(loss) from continuing operations before income taxes		(7	)		132		28		(4	)		31		4		(150	)		(20	)		14
Income on discontinued operations, net of income taxes		—			—		—		—			1		—		10			—			11

Net income/(loss)	$	18		$	132	$	28	$	(2	)	$	23	$	4	$	(157	)	$	(20	)	$	26


(a)		For the period February 2, 2006 to March 31, 2006.

(b)		Only included the equity earnings of WCP.

Note 10 — Income Taxes

Income tax expense for the three months ended March 31, 2007 was $56 million and an income tax benefit of $1 million for the three months ended March 31, 2006. The income tax expense for the three months ended March 31, 2007 included domestic tax expense of $48 million and foreign tax expense of $8 million. The income tax benefit for the three months ended March 31, 2006 included domestic tax benefit of $10 million and foreign tax expense of $9 million.

A reconciliation of the U.S. statutory rate to NRG’s effective tax rate from continuing operations for the three months ended March 31, 2007 and 2006 is as follows:


(In millions except rate data)
Three months ended March 31,	2007			2006

Income from continuing operations before income taxes	$	121		$	14
Tax at 35%		42			5
State taxes		6			2
Valuation allowance		—			2
Disputed claims reserve		—			(7	)
Foreign operations		(1	)		(6	)
Foreign dividend		5			1
Permanent differences including subpart F income and non-deductible interest expense		4			2

Income tax expense/(benefit)	$	56		$	(1	)

Effective income tax rate		46.3	%		(7.1	)%

The effective income tax rate for the three months ended March 31, 2007 and 2006 differs from the U.S. statutory rate of 35% due to a taxable dividend from foreign operations and non-deductible interest, offset by earnings in foreign jurisdictions that are taxed at rates lower than the U.S. statutory rate.

Deferred tax assets and valuation allowance

Net deferred tax balance — As of March 31, 2007, NRG recorded a net deferred tax asset of $30 million. However, due to an assessment of positive and negative evidence, including projected capital gains and available tax planning strategies, NRG believes that it is more likely than not that a benefit will not be realized on $583 million of tax assets, thus a valuation allowance has remained, resulting in a net deferred tax liability of $553 million.

NOL carryforwards — As of March 31, 2007, the Company had NOL carryforwards available for domestic income tax purposes of $70 million that will expire through 2027. In addition, NRG has cumulative foreign NOL carryforwards of $273 million of which $73 million will expire in 2016 and of which $200 million does not have an expiration date.

Uncertain tax benefits

NRG has identified certain unrecognized tax benefits whose after tax value was $712 million, and if recognized, $19 million will impact the Company’s effective tax rate. Of the $712 million in unrecognized tax benefits, $693 million relates to periods prior to the Company’s emergence from bankruptcy, and in accordance with SOP 90-7 and the application of Fresh Start accounting, any recognized benefit would not impact the Company’s effective tax rate but would increase Additional Paid In Capital. NRG has accrued interest and penalty related to these unrecognized tax benefits of approximately $4 million as of the adoption of FIN 48 by the Company on January 1, 2007. There were no interest and penalties related to unrecognized tax benefits that were recognized in the Company’s results of operations for the three months ended March 31, 2007.

Tax jurisdictions — NRG is subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and foreign jurisdictions including major operations located in Germany, Australia, and Brazil. The Company is no longer subject to U.S. federal income tax examinations for years prior to 2002. With few exceptions, state and local income tax examinations are no longer open for years before 2003. The Company’s significant foreign operations are also no longer subject to examination by local jurisdictions for years prior to 2000.

Note 11 — Benefit Plans and Other Postretirement Benefits

The net annual periodic pension cost for the three months ended March 31, 2007 and 2006 related to all of the Company’s defined benefit pension plans, include the following components:


(In millions)	Defined Benefit Pension Plans
Three months ended March 31	2007			2006

Service cost benefits earned	$	4		$	4
Interest cost on benefit obligation		4			3
Expected return on plan assets		(3	)		(1	)

Net periodic benefit cost	$	5		$	6

The net annual periodic cost for the three months ended March 31, 2007 and 2006 related to all of the Company’s other post retirement benefits plans, include the following components:


(In millions)	Other Postretirement Benefits Plans
Three months ended March 31	2007		2006

Service cost benefits earned	$	1	$	1
Interest cost on benefit obligation		1		1

Net periodic benefit cost	$	2	$	2

The total amount of employer contributions paid for the three months ended March 31, 2007 was $12 million.

Note 12 — Commitments and Contingencies

Commitments

Second Lien Structure

NRG has granted second priority liens to certain counterparties on substantially all of the Company’s assets in the United States in order to secure obligations, which are primarily long-term in nature under certain power sale agreements and related contracts. NRG uses the second lien structure to reduce the amount of cash collateral and letters of credit that it may otherwise be required to post from time to time to support its obligations under these agreements. Within the second lien structure, the Company can hedge up to 80% of its baseload capacity and 10% of its non-baseload assets with these counterparties. As of March 31, 2007, the net discounted exposure on the agreements and hedges that were subject to the second lien structure was approximately $90 million.

Coal Commitments

NRG enters into long-term contractual arrangements to procure fuel and transportation services for the Company’s generation assets. NRG entered into additional coal purchase agreements during the first quarter 2007 with total commitments of approximately $303 million spanning over the next six years.

Contingencies

Set forth below is a description of the Company’s material legal proceedings. Pursuant to the requirements of SFAS 5, Accounting for Contingencies, and related guidance, NRG records reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss is reasonably estimable. Because litigation is subject to inherent uncertainties and unfavorable rulings or developments could occur, there can be no certainty that NRG may not ultimately incur charges in excess of presently recorded reserves. A future adverse ruling or unfavorable development could result in future charges, which could have a materially adverse effect on NRG’s consolidated financial position, results of operations, or cash flows.

With respect to a number of the items listed below, management has determined that a loss is not probable or the amount of the loss

is not reasonably estimable, or both. In some cases, management is not able to predict with any degree of substantial certainty the range of possible loss that could be incurred. Notwithstanding these facts, management has assessed each of these 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. Management’s judgment may, as a result of facts arising prior to resolution of these matters, or other factors, prove inaccurate and investors should be aware that such judgment is made subject to the uncertainty of litigation.

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 effect NRG’s consolidated financial position, results of operations, or cash flows.

NRG believes that it has valid defenses to the legal proceedings and investigations described below and intends to defend them vigorously. However, litigation is inherently subject to many uncertainties. There can be no assurance that additional litigation will not be filed against the Company or its subsidiaries in the future, asserting similar or different legal theories and seeking similar or different types of damages and relief. Unless specified below, the Company is unable to predict the outcome of these legal proceedings and investigations may have or reasonably estimate the scope or amount of any associated costs and potential liabilities. An unfavorable outcome in one or more of these proceedings could have a material impact on the Company’s consolidated financial position, results of operations, or cash flows. NRG also has indemnity rights for some of these proceedings to reimburse NRG for certain legal expenses and to offset certain amounts deemed to be owed in the event of an unfavorable litigation outcome.

California Electricity and Related Litigation

NRG, WCP, WCP’s four operating subsidiaries, Dynegy, Inc., and numerous other unrelated parties are the subject of numerous lawsuits that arose based on events that occurred in the California power market in 2000 and 2001. The complaints primarily allege that the defendants engaged in unfair business practices, price fixing, antitrust violations, and other market gaming activities. Certain of these lawsuits originally commenced in 2000 and 2001, which seek unspecified treble damages and injunctive relief, were consolidated and made a part of a Multi-District Litigation proceeding before the U.S. District Court for the Southern District of California. The consolidated cases moved between state and federal court several times. On May 5, 2005, the case was remanded to California state court, and under a scheduling order, defendants filed their objections to the pleadings. On July 22, 2005, based upon the filed rate doctrine and federal preemption, the court dismissed NRG Energy, Inc. without prejudice, leaving only subsidiaries of WCP remaining in the case. On October 3, 2005, the court sustained defendants’ demurrer, dismissing the case against all remaining defendants. On December 2, 2005, the plaintiffs filed their notice of appeal from the dismissal with the California State Court of Appeals — Fourth District and on February 26, 2007, the court affirmed the lower court’s judgment of dismissal. Other cases, including putative class actions, have been filed in state and federal court on behalf of business and residential electricity consumers that name WCP and/or subsidiaries of WCP, in addition to numerous other defendants. These complaints allege the defendants attempted to manipulate gas indexes by reporting false and fraudulent trades, and violated California’s antitrust law and unfair business practices law. The complaints seek restitution and disgorgement, civil fines, compensatory and punitive damages, attorneys’ fees, and declaratory and injunctive relief. Motion practice is proceeding in these cases and dispositive motions have been filed in several of these proceedings.

In September 2006, Dynegy executed a settlement agreement to resolve the class action claims in the natural gas anti-trust cases consolidated and pending in state court in San Diego, California. Approved in late December 2006, the Court has dismissed the class action claims. WCP and some of its subsidiaries were named defendants and Dynegy’s settlement includes full releases for these entities. The settlement resolves claims by core and non-core California consumers of natural gas for damages arising from or relating to allegations of misreporting of natural gas transactions or wash trading. Preliminarily approved by the court, the settlement excludes similar cases filed by individual plaintiffs, which Dynegy continues to defend. Neither WCP and its subsidiaries nor NRG paid any defense costs or settlement funds, as Dynegy owed and provided a complete defense and indemnification.

In August 2006, Dynegy entered into an agreement to settle class action claims by California natural gas resellers and cogenerators. These claims are pending in Nevada federal district court in “In Re Western States Wholesale Natural Gas Antitrust Litigation”. WCP and its subsidiaries are named defendants and Dynegy’s settlement would include full releases for these entities. The settlement is expected to be submitted to the court for approval in 2007. Neither WCP, its subsidiaries, nor NRG paid any defense costs or settlement funds, as Dynegy owed and provided a complete defense and indemnification.

In cases relating to natural gas, Dynegy is defending WCP and/or its subsidiaries pursuant to an indemnification agreement and will be the responsible party for any loss. In cases relating to electricity, Dynegy’s counsel is representing it and WCP and/or its subsidiaries, with each party responsible for half of the costs and each party responsible for half of any loss.

California Department of Water Resources

On December 19, 2006, the U.S. Court of Appeals for the Ninth Circuit reversed FERC’s prior determinations regarding the enforceability of certain wholesale power contracts and remanded the case to FERC for further proceedings consistent with the decision. One of these contracts was the wholesale power contract between the California Department of Water Resources, or CDWR, and subsidiaries of WCP. This case originated with a February 2002 complaint filed at FERC by the State of California alleging that many parties, including WCP subsidiaries, overcharged the State. For WCP, the alleged overcharges totaled approximately $940 million for 2001 and 2002. The complaint demanded that FERC abrogate the CDWR contract and sought refunds associated with revenues collected under the contract. In 2003, FERC rejected this complaint, denied rehearing, and the case was appealed to the Ninth Circuit where oral argument was held on December 8, 2004. On December 19, 2006, the Court decided that in FERC’s review of the contracts at issue, FERC could not rely on the Mobile-Sierra standard presumption of just and reasonable rates, where such contracts were not reviewed by FERC with full knowledge of the then existing market conditions. WCP and the other defendants expect to seek review by the U.S. Supreme Court prior to the May 3, 2007, deadline. The Supreme Court is expected to decide in 2007 whether it will accept the appeal. 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 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.

Connecticut Congestion Charges

On November 28, 2001, CL&P sought recovery in the U.S. District Court for Connecticut for amounts it claimed were owed for congestion charges under the October 29, 1999 Standard Offer Services Contract. CL&P withheld approximately $30 million from amounts owed to PMI under contract and PMI counterclaimed. CL&P’s motion for summary judgment, which PMI opposed, remains pending. NRG cannot estimate at this time the overall exposure for congestion charges for the term of the contract prior to the implementation of standard market design, which occurred on March 1, 2003; however, the full amount withheld by CL&P has been reserved as a reduction to outstanding accounts receivable.

Station Service Disputes

On October 2, 2000, NiMo commenced an action against NRG in New York state court seeking damages related to NRG’s alleged failure to pay retail tariff amounts for utility services at the Dunkirk Plant between June 1999 and September 2000. The parties agreed to consolidate this action with two other actions against the Huntley and Oswego Plants. On October 8, 2002, by stipulation and order, this action was stayed pending submission to FERC of the disputes in the action. At FERC, NiMo asserted the same claims and legal theories, and on November 19, 2004, FERC denied NiMo’s petition and ruled that the NRG facilities could net their service obligations over each 30 calendar day period from the day NRG acquired the facilities. In addition, FERC ruled that neither NiMo nor the New York Public Service Commission could impose a retail delivery charge on the NRG facilities because they are interconnected to transmission and not to distribution. On April 22, 2005, FERC denied NiMo’s motion for rehearing. NiMo appealed to the U.S. Court of Appeals for the D.C. Circuit which, on June 23, 2006, denied the appeal finding that NYISO’s station service program that permits generators to self supply their station power needs by netting consumption against production in a month is lawful. On October 23, 2006, the D.C. Circuit denied NiMo’s petition for rehearing and on January 22, 2007, NiMo sought review before the U.S. Supreme Court. On April 30, 2007, the U.S. Supreme Court denied NiMo’s request for the review thus ending further avenues to appeal FERC’s ruling in this matter. NRG currently believes it is adequately reserved.

On December 14, 1999, NRG acquired certain generating facilities from CL&P. A dispute arose over station service power and delivery services provided to the facilities. On December 20, 2002, as a result of a petition filed at FERC by Northeast Utilities Services Company on behalf of itself and CL&P, FERC issued an order finding that, at times when NRG is not able to self-supply its station power needs, there is a sale of station power from a third-party and retail charges apply. In August 2003, the parties agreed to submit the dispute to binding arbitration. In July and August 2006, the parties submitted their respective statements of the case to the three member arbitration panel. A discovery and briefing schedule was issued and a hearing is set for September 2007. NRG believes it is adequately reserved.

ITISA

NRG’s Brazilian project company, ITISA, the owner of a 155 MW hydro project in Brazil, is in arbitration with the former Engineering, Procurement and Construction, or EPC, contractor for the project, Inepar Industria e Construcoes, or Inepar. The dispute was commenced in arbitration by ITISA in September 2002 and pertains to certain matters arising under the EPC contract between the parties. ITISA sought Real 140 million and asserted that Inepar breached the contract. Inepar sought Real 39 million and alleged that ITISA breached the contract. On September 2, 2005, the arbitration panel ruled in favor of ITISA, awarding it Real 139 million and Inepar Real 4.7 million. Due to interest accrued from the commencement of the arbitration to the award date, ITISA’s award was increased to approximately Real 227 million (approximately $110 million as of March 31, 2007). ITISA has commenced the lengthy process in Brazil to execute on the arbitral award. NRG is unable to predict the outcome of this execution process. On December 21, 2005, Inepar’s request for clarifications was denied. Due to the uncertainty of the ongoing collection process, NRG is accounting for receipt of any amounts as a gain contingency.

Disputed Claims Reserve

As part of NRG’s plan of reorganization, NRG funded a disputed claims reserve for the satisfaction of certain general unsecured claims that were disputed claims as of the effective date of the plan. Under the terms of the plan, as such claims are resolved, the claimants are paid from the reserve on the same basis as if they had been paid out in the bankruptcy. To the extent the aggregate amount required to be paid on the disputed claims exceeds the amount remaining in the funded claims reserve, NRG will be obligated to provide additional cash and common stock to satisfy the claims. Any excess funds in the disputed claims reserve will be reallocated to the creditor pool for the pro rata benefit of all allowed claims. The contributed common stock and cash in the reserves is held by an escrow agent to complete the distribution and settlement process. Since NRG has surrendered control over the common stock and cash provided to the disputed claims reserve, NRG recognized the issuance of the common stock as of December 6, 2003 and removed the cash amounts from the balance sheet. Similarly, NRG removed the obligations relevant to the claims from the balance sheet when the common stock was issued and cash contributed.

On April 3, 2006, the Company made a supplemental distribution to creditors under the Company’s Chapter 11 plan, totaling $25 million in cash and 2,541,000 shares of common stock. As of April 18, 2007, the reserve held approximately $10 million in cash and approximately 691,709 shares of common stock. NRG believes the cash and stock together represent sufficient funds to satisfy all remaining disputed claims.

Note 13 — Regulatory Matters

With the exception of NRG’s thermal and chilled water business and decommissioning responsibilities related to STP, NRG’s operations are not regulated operations subject to SFAS 71 and NRG does not record assets and liabilities that result from the regulated ratemaking processes. NRG does operate, however, in a highly regulated industry and the Company 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.

Northeast Region

New England — On December 28, 2006, the Attorneys General of the State of Connecticut and Commonwealth of Massachusetts filed an appeal of the FERC orders accepting the settlement of the New England capacity market design with the U.S. Court of Appeals for the D.C. Circuit. The settlement, filed March 7, 2006, by a broad group of New England market participants, provides for interim capacity transition payments for all generators in New England for the period starting December 1, 2006 through May 31, 2010, and the establishment of a Forward Capacity Market, or FCM, commencing May 31, 2010. On June 16, 2006, FERC issued an order accepting the settlement, which was reaffirmed on rehearing by order dated October 31, 2006. Interim capacity transition payments provided for under the FCM settlement commenced December 1, 2006, as scheduled. A successful appeal by the Attorneys General could disturb the settlement and create a refund obligation of interim capacity transition payments. On April 5, 2007, the Connecticut Attorney General filed a motion seeking to stay the interim capacity transition payments.

New York — A dispute is ongoing with respect to high prices for spinning reserves, or SR, and non-spinning reserves, or NSR, in the NYISO-administered markets during the period from January 29, 2000 to March 27, 2000. Certain entities have argued that the NYISO acted unreasonably in declining to invoke Temporary Extraordinary Operating Procedures, or TEP, to recalculate prices and that the markets should be resettled for various reasons. In a series of orders, FERC declined to grant the requested relief. On appeal, the U.S. Court of Appeals for the D.C. Circuit remanded the case back to FERC to further explain its decision not to utilize TEP to remedy certain of these market issues. On March 4, 2005, FERC issued an order reaffirming that (i) the NYISO acted reasonably in not invoking TEP, (ii) NYISO did not violate its tariff, and (iii) refunds should not be granted; this order was reaffirmed on rehearing

on November 17, 2005. These orders have subsequently been appealed to the D.C. Circuit. Resettlement of the market, while viewed as unlikely, could have a material financial impact on the Company’s results of operations.

West Region

On December 1, 2006, NRG filed to extend the existing RMR agreements for NRG’s Cabrillo Power I, LLC (Encina) and Cabrillo Power II, LLC (San Diego Jets) for 2007, seeking to continue the then-existing rate effective January 1, 2007. On January 24, 2007, FERC accepted the Cabrillo Power I filing. On January 30, 2007, FERC accepted the Cabrillo II filing, subject to refund, in response to protests filed by the CPUC and CAISO, and established settlement procedures. The parties have reached a settlement in principle that will result in an annual fixed revenue requirement of approximately $5 million.

Note 14 — Environmental Matters

The construction and operation of power projects are subject to stringent environmental and safety protection and land use laws and regulation in the U.S. If such laws and regulations become more stringent, or new laws, interpretations or compliance policies apply and NRG’s facilities are not exempt from coverage, the Company could be required to make modifications to further reduce potential environmental impacts. In addition, increased public concern and mounting political pressure may result in federal or additional state requirements to reduce or mitigate the effects of greenhouse gases emissions, including carbon dioxide. 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 $1.3 billion of capital expenditures will be incurred during the period 2007 through 2012 in order to keep NRG’s facilities in compliance with environmental laws. These expenditures are primarily related to installation of particulate, SO₂, NO_x, and mercury controls to comply with Clean Air Interstate Rule, or CAIR, and the Clean Air Mercury Rule, or CAMR, as well as installation of Best Technology Available under the Phase II 316(b) Rule. NRG typically updates its estimates for environmental capital expenditures annually. These plans, including installed equipment and timing as well as cost can be expected to change over time, in some cases materially. These plans are based on current regulatory requirements and best engineering practices. Changes to regulations or market conditions could result in changes to installed equipment timing or associated costs. Depending upon the outcome of the challenge to DNREC’s Regulation No. 1146 discussed below, NRG will reassess its options for its Indian River power plant and associated costs.

Other Environmental Matters

Under various federal, state, and local environmental laws and regulations, a current or previous owner or operator of any facility may be required to investigate and remediate releases or threatened releases of hazardous or toxic substances or petroleum products located at a facility, and may be held liable to a governmental entity or to third parties for property damage, personal injury and investigation and remediation costs incurred by the party in connection with any releases or threatened releases. These laws impose strict (without fault) and joint and several liability. The cost of investigation, remediation, or removal of any hazardous or toxic substances or petroleum products could be substantial.

Texas Region

The lignite used to fuel the Texas region’s Limestone facility is obtained from a surface mine adjacent to the facility under an amended long-term contract with Texas Westmoreland Coal Co., or TWCC, entered into in August 1999. TWCC is responsible for performing ongoing reclamation activities at the mine until all lignite reserves have been produced. When production is completed at the mine, NRG will be responsible for final mine reclamation obligations. The Railroad Commission of Texas has imposed a bond obligation of approximately $70 million on TWCC for the reclamation of this lignite mine. Final reclamation activity is expected to commence in 2015. Pursuant to the contract with TWCC, an affiliate of CenterPoint Energy, Inc. has guaranteed $50 million of this obligation until 2010. The remaining sum of approximately $20 million has been bonded by the mine operator, TWCC. Under the terms of the agreement, NRG is required to post a corporate guarantee of TWCC's bond obligation in the amount of $50 million when CenterPoint’s obligation lapses. As of March 31, 2007, NRG has established an ARO of approximately $20 million related to the mine reclamation obligation.

Northeast Region

In January 2006, NRG Indian River Operations, Inc. received a letter of informal notification from the Delaware Department of Natural Resources and Environmental Control, or DNREC, stating that it may be a potentially responsible party with respect to a

historic captive landfill. NRG is working with DNREC through the Voluntary Clean-up Program to investigate the site. The Company is unable to predict the financial impact at this time.

In November 2006, DNREC promulgated Regulation No. 1146, or Reg 1146, Electric Generating Unit Multi-Pollutant Regulation and Section 111(d) of the State Plan for the Control of Mercury Emissions from Coal-Fired Electric Steam Generating Units. These regulations govern the control of SO₂, NO_x, and mercury emissions from electric generating units. NRG’s current plan to install controls at the Company’s Indian River facility, while on an accelerated basis, is unable to meet certain deadlines for SO₂ and NO_x controls in Phase 1, taking into account the time required, as a practical matter, to design, install, and commission the necessary equipment. NRG and the owners of all other subject facilities in the state filed a challenge to Reg 1146 with the Environmental Appeals Board, or EAB, on December 6, 2006. In addition, NRG also filed a protective appeal with the Delaware Superior Court on December 29, 2006. A hearing is scheduled to commence before the EAB on June 18, 2007. NRG is unable to predict the outcome of the proceedings at this time, but failure to obtain relief may result in a material impact on the Company’s results of operations.

South Central Region

On January 27, 2004, NRG’s Louisiana Generating, LLC and the Company’s Big Cajun II plant received a request under Section 114 of the Clean Air Act, or CAA, from USEPA seeking information primarily related to physical changes made at the Big Cajun II plant, and subsequently received a notice of violation, or NOV, on February 15, 2005, alleging that NRG’s predecessors had undertaken projects that triggered requirements under the PSD program, including the installation of emission controls. NRG submitted multiple responses commencing February 27, 2004 and ending on October 20, 2004. On May 9, 2006, these entities received from the Department of Justice, or DOJ, a notice of deficiency related to their responses, to which NRG responded on May 22, 2006. A document review was conducted at NRG’s Louisiana Generating, LLC offices by the DOJ during the week of August 14, 2006. On December 8, 2006, the USEPA issued a supplemental NOV updating the original February 15, 2005 NOV. Discussions with the USEPA are ongoing and the Company cannot predict with certainty the outcome of this matter.

Note 15 — 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, joint venture agreements, operation and maintenance agreements, service agreements, settlement agreements, and other types of contractual agreements with vendors and other third parties. 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. In some cases, NRG’s maximum potential liability cannot be estimated, since the underlying agreements contain no limits on potential liability.

This footnote should be read in conjunction with the complete description under Note 25, Guarantees, to the Company’s financial statements in its Annual Report on Form 10-K for the year ended December 31, 2006.

For the three months ended March 31, 2007, NRG had net increases to its guarantee obligations under other commercial arrangements of approximately $128 million. These pertain to payment obligations of NRG Power Marketing, Inc., or PMI.

Note 16 — Condensed Consolidating Financial Information

As of March 31, 2007, the Company had $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 outstanding. These notes are guaranteed by certain of NRG’s current and future wholly-owned domestic subsidiaries, or guarantor subsidiaries.

Each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of March 31, 2007:


Arthur Kill Power LLC		NRG Connecticut Affiliate Services Inc.
Astoria Gas Turbine Power LLC		NRG Devon Operations Inc.
Berrians I Gas Turbine Power LLC		NRG Dunkirk Operations Inc.
Big Cajun II Unit 4 LLC		NRG El Segundo Operations Inc.
Cabrillo Power I LLC		NRG Generation Holdings, Inc.
Cabrillo Power II LLC		NRG Huntley Operations Inc.


Chickahominy River Energy Corp.		NRG International LLC
Commonwealth Atlantic Power LLC		NRG Kaufman LLC
Conemaugh Power LLC		NRG Mesquite LLC
Connecticut Jet Power LLC		NRG MidAtlantic Affiliate Services Inc.
Devon Power LLC		NRG Middletown Operations Inc.
Dunkirk Power LLC		NRG Montville Operations Inc.
Eastern Sierra Energy Company		NRG New Jersey Energy Sales LLC
El Segundo Power, LLC		NRG New Roads Holdings LLC
El Segundo Power II LLC		NRG North Central Operations Inc.
GCP Funding Company, LLC		NRG Northeast Affiliate Services Inc.
Hanover Energy Company		NRG Norwalk Harbor Operations Inc.
Hoffman Summit Wind Project, LLC		NRG Operating Services, Inc.
Huntley IGCC LLC		NRG Oswego Harbor Power Operations Inc.
Huntley Power LLC		NRG Power Marketing Inc.
Indian River IGCC LLC		NRG Rocky Road LLC
Indian River Operations Inc.		NRG Saguaro Operations Inc.
Indian River Power LLC		NRG South Central Affiliate Services Inc.
James River Power LLC		NRG South Central Generating LLC
Kaufman Cogen LP		NRG South Central Operations Inc.
Keystone Power LLC		NRG South Texas LP
Lake Erie Properties Inc.		NRG Texas LLC
Louisiana Generating LLC		NRG Texas LP
Middletown Power LLC		NRG West Coast LLC
Montville IGCC LLC		NRG Western Affiliate Services Inc.
Montville Power LLC		Oswego Harbor Power LLC
NEO Chester-Gen LLC		Padoma Wind Power, LLC
NEO Corporation		Saguaro Power LLC
NEO Freehold-Gen LLC		San Juan Mesa Wind Project II, LLC
NEO Landfill Gas Holdings Inc.		Somerset Operations Inc.
NEO Power Services Inc.		Somerset Power LLC
New Genco GP, LLC		Texas Genco Financing Corp.
New Genco LP, LLC		Texas Genco GP, LLC
Norwalk Power LLC		Texas Genco Holdings, Inc.
NRG Affiliate Services Inc.		Texas Genco LP, LLC
NRG Arthur Kill Operations Inc.		Texas Genco Operating Services, LLC
NRG Asia-Pacific, Ltd.		Texas Genco Services, LP
NRG Astoria Gas Turbine Operations Inc.		Vienna Operations Inc.
NRG Bayou Cove LLC		Vienna Power LLC
NRG Cabrillo Power Operations Inc.		WCP (Generation) Holdings LLC
NRG Cadillac Operations Inc.		West Coast Power LLC
NRG California Peaker Operations LLC

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

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

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

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended March 31, 2007


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

Operating Revenues
Total operating revenues	$	1,215		$	95		$	—		$	—		$	1,310

Operating Costs and Expenses
Cost of operations		716			66			2			—			784
Depreciation and amortization		153			7			1			—			161
General and administrative		28			3			55			—			86
Development costs		23			—			—			—			23

Total operating costs and expenses		920			76			58			—			1,054
Gain on sale of assets		18			—			(1	)		—			17

Operating Income/(Loss)		313			19			(59	)		—			273
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries		32			—			156			(188	)		—
Equity in earnings of unconsolidated affiliates		(2	)		15			—			—			13
Other income, net		2			9			10			(5	)		16
Interest expense		(70	)		(26	)		(90	)		5			(181	)

Total other income/( expense)		(38	)		(2	)		76			(188	)		(152	)

Income From Continuing Operations Before Income Taxes		275			17			17			(188	)		121
Income Tax Expense/(Benefit)		99			5			(48	)		—			56

Net Income	$	176		$	12		$	65		$	(188	)	$	65


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

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
March 31, 2007


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


ASSETS
Current Assets
Cash and cash equivalents	$	—		$	170		$	534		$	—		$	704
Accounts receivable, net		369			40			—			—			409
Inventory		387			13			—			—			400
Derivative instruments valuation		853			—			1			—			854
Prepayments and other current assets		213			13			200			(124	)		302

Total current assets		1,822			236			735			(124	)		2,669

Net property, plant and equipment		11,104			399			18			—			11,521
Other Assets
Investment in subsidiaries		488			—			9,155			(9,643	)		—
Equity investments in affiliates		28			333			—			—			361
Notes receivable and capital lease		1,027			476			5,474			(6,501	)		476
Goodwill		1,787			—			—			—			1,787
Intangible assets, net		957			1			—			—			958
Nuclear decommissioning trust		357			—			—			—			357
Derivative instruments valuation		182			—			5			—			187
Other non-current assets		24			84			175			—			283
Intangible assets held-for-sale		112			—			—			—			112

Total other assets		4,962			894			14,809			(16,144	)		4,521

Total Assets	$	17,888		$	1,529		$	15,562		$	(16,268	)	$	18,711

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt	$	40		$	100		$	36		$	(47	)	$	129
Accounts payable		(850	)		271			874			—			295
Derivative instruments valuation		824			—			—			—			824
Accrued expenses and other current liabilities		340			65			(8	)		(77	)		320

Total current liabilities		354			436			902			(124	)		1,568
Other Liabilities
Long-term debt		5,474			837			8,827			(6,501	)		8,637
Nuclear decommissioning reserve		280			—			—			—			280
Nuclear decommissioning trust liability		335			—			—			—			335
Deferred income taxes		532			(123	)		214			—			623
Derivative instruments valuation		394			6			18			—			418
Out-of-market contracts		839			—			—			—			839
Other long-term obligations		379			30			28			—			437

Total non-current liabilities		8,233			750			9,087			(6,501	)		11,569

Total liabilities		8,587			1,186			9,989			(6,625	)		13,137

Minority interest		—			1			—			—			1
3.625% Preferred Stock		—			—			247			—			247
Stockholders’ Equity		9,301			342			5,326			(9,643	)		5,326

Total Liabilities and Stockholders’ Equity	$	17,888		$	1,529		$	15,562		$	(16,268	)	$	18,711


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

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2007


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

Cash Flows from Operating Activities
Net income	$	176		$	12		$	65		$	(188	)	$	65
Adjustments to reconcile net income to net cash provided by operating activities
Distributions less than equity earnings of unconsolidated affiliates and consolidated subsidiaries		272			(12	)		146			(416	)		(10	)
Depreciation and amortization of nuclear fuel		166			7			1			—			174
Amortization of financing costs and debt discount		—			2			7			—			9
Amortization of intangibles and out-of-market contracts		(29	)		—			—			—			(29	)
Amortization of unearned equity compensation		—			—			7			—			7
Changes in deferred income taxes		21			(3	)		29			—			47
Changes in nuclear decommissioning liability		9			—			—			—			9
Changes in derivatives		91			1			(2	)		—			90
Gain on sale of assets		(17	)		—			—			—			(17	)
Gain on sale of emission allowances		(5	)		—			—			—			(5	)
Changes in collateral deposits supporting energy risk management activities		(120	)		—			—			—			(120	)
Cash provided by/(used by) changes in other working capital, net of dispositions affects		(155	)		(11	)		52			—			(114	)

Net Cash Provided by Operating Activities		409			(4	)		305			(604	)		106
Cash Flows from Investing Activities
Proceeds from payment of intercompany loans		—			—			12			(12	)		—
Capital expenditures		(106	)		(1	)		—			—			(107	)
Decrease/(increase) in restricted cash		—			(5	)		—			—			(5	)
Decrease/(increase) in notes receivable		—			9			—			—			9
Purchases of emission allowances		(61	)		—			—			—			(61	)
Proceeds from sale of emission allowances		32			—			—			—			32
Proceeds from sale of assets		29			—			—			—			29
Purchases in trust fund securities		(68	)		—			—			—			(68	)
Proceeds from sales of trust fund securities		59			—			—			—			59

Net Cash Provided/Used by Investing Activities		(115	)		3			12			(12	)		(112	)
Cash Flows from Financing Activities
Payments to Parent for intercompany loans		(12	)		—			—			12			—
Payments from intercompany dividends		(302	)		(302	)		—			604			—
Payments for dividends to preferred stockholders		—			—			(14	)		—			(14	)
Payments for treasury stock		—			—			(103	)		—			(103	)
Payments for short and long-term debt		(1	)		(9	)		(9	)		—			(19	)

Net Cash Used by Financing Activities		(315	)		(311	)		(126	)		616			(136	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents		—			2			—			—			2

Net Increase/(Decrease) in Cash and Cash Equivalent		(21	)		(310	)		191			—			(140	)
Cash and Cash Equivalents at Beginning of Period		20			432			343			—			795

Cash and Cash Equivalents at End of Period	$	(1	)	$	122		$	534		$	—		$	655


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

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2006


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

ASSETS
Current Assets
Cash and cash equivalents	$	20		$	432		$	343	$	—		$	795
Restricted cash		1			43			—		—			44
Accounts receivable-trade, net		332			40			—		—			372
Inventory		408			13			—		—			421
Derivative instruments valuation		1,230			—			—		—			1,230
Prepayments and other current assets		200			32			736		(747	)		221

Total current assets		2,191			560			1,079		(747	)		3,083

Net property, plant and equipment		11,178			403			19		—			11,600
Other Assets
Investment in subsidiaries		730			—			9,163		(9,893	)		—
Equity investments in affiliates		31			313			—		—			344
Notes receivable and capital lease		1,015			479			5,503		(6,518	)		479
Goodwill		1,789			—			—		—			1,789
Intangible assets, net		977			4			—		—			981
Nuclear decommissioning trust fund		352			—			—		—			352
Derivative instruments valuation		424			—			15		—			439
Other non-current assets		51			56			182		—			289
Intangible assets held-for-sale		78			—			1		—			79

Total other assets		5,447			852			14,864		(16,411	)		4,752

Total Assets	$	18,816		$	1,815		$	15,962	$	(17,158	)	$	19,435

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt	$	460		$	101		$	37	$	(468	)	$	130
Accounts payable		(682	)		287			727		—			332
Derivative instruments valuation		964			—			—		—			964
Deferred income taxes		23			7			134		—			164
Accrued expenses and other current liabilities		509			53			160		(280	)		442

Total current liabilities		1,274			448			1,058		(748	)		2,032

Other Liabilities
Long-term debt and capital lease		5,504			869			8,791		(6,517	)		8,647
Nuclear decommissioning reserve		289			—			—		—			289
Nuclear decommissioning trust liability		324			—			—		—			324
Deferred income taxes		494			(104	)		164		—			554
Derivative instruments valuation		325			6			20		—			351
Out-of-market contracts		897			—			—		—			897
Other non-current liabilities		385			26			24		—			435

Total non-current liabilities		8,218			797			8,999		(6,517	)		11,497

Total liabilities		9,492			1,245			10,057		(7,265	)		13,529

Minority interest		—			1			—		—			1
3.625% Preferred Stock		—			—			247		—			247
Stockholders’ Equity		9,324			569			5,658		(9,893	)		5,658

Total Liabilities and Stockholders’ Equity	$	18,816		$	1,815		$	15,962	$	(17,158	)	$	19,435


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

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended March 31, 2006


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

Operating Revenues
Total operating revenues	$	957		$	86		$	—		$	—		$	1,043

Operating Costs and Expenses
Cost of operations		596			61			2			—			659
Depreciation and amortization		111			6			1			—			118
General and administrative		22			—			35			—			57

Total operating costs and expenses		729			67			38			—			834

Operating Income		228			19			(38	)		—			209
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries		22			—			161			(183	)		—
Equity in earnings of unconsolidated affiliates		—			21			—			—			21
Write down of equity method investment		(3	)		—			—			—			(3	)
Other income, net		3			75			7			(5	)		80
Refinancing expenses		—			—			(178	)		—			(178	)
Interest expense		(54	)		(16	)		(50	)		5			(115	)

Total other income/(expense)		(32	)		80			(60	)		(183	)		(195	)

Income From Continuing Operations Before Income Taxes		196			99			(98	)		(183	)		14
Income tax expense/(benefit)		85			35			(121	)		—			(1	)

Income From Continuing Operations		111			64			23			(183	)		15
Income from discontinued operations, net of income taxes		—			8			3			—			11

Net Income	$	111		$	72		$	26		$	(183	)	$	26


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

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2006


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

Cash Flows from Operating Activities
Net income	$	111		$	72		$	26		$	(183	)	$	26
Adjustments to reconcile net income to net cash provided by operating activities
Distributions more/(less) than equity earnings of unconsolidated affiliates and consolidated subsidiaries		22			(12	)		161			(183	)		(12	)
Depreciation and amortization of nuclear fuel		111			12			2			—			125
Amortization of financing costs and debt discount		—			2			8			—			10
Amortization of intangibles and out-of-market contracts		3			6			—			—			9
Amortization of unearned equity compensation		—			—			3			—			3
Write-off of deferred financing costs and debt premium		—			—			47			—			47
Write down of equity method investments		3			—			—			—			3
Changes in deferred income taxes		28			3			15			—			46
Changes in nuclear decommissioning liability		(3	)		—			—			—			(3	)
Changes in derivatives		(23	)		(2	)		4			—			(21	)
Gain on sale of emission allowances		(59	)		—			—			—			(59	)
Gain on legal settlement		—			(67	)		—			—			(67	)
Gain on sale of discontinued operations		—			(10	)		—			—			(10	)
Changes in collateral deposits supporting energy risk management activities		230			—			—			—			230
Cash provided by(used by) changes in other working capital, net of dispositions affects		(281	)		36			(106	)		366			15

Net Cash Provided by Operating Activities		142			40			160			—			342
Cash Flows from Investing Activities
Acquisition of Texas Genco LLC and WCP		—			—			(4,288	)		—			(4,288	)
Capital expenditures		(32	)		(3	)		—			—			(35	)
Decrease/(increase) in restricted cash		—			(3	)		—			—			(3	)
Changes in notes receivable		—			8			(2,760	)		2,760			8
Investments in trust fund securities		(42	)		—			—			—			(42	)
Purchases of emission allowances		(15	)		—			—			—			(15	)
Proceeds from the sale of emission allowances		68			—			—			—			68
Proceeds from sales of trust fund securities		45			—			—			—			45
Proceeds from sale of investments		45			—			—			—			45
Proceeds from sale of discontinued operations		—			15			—			—			15

Net Cash Used by Investing Activities		69			17			(7,048	)		2,760			(4,202	)
Cash Flows from Financing Activities
Payments for dividends to preferred stockholders		—			—			(10	)		—			(10	)
Payment of financing element of acquired derivatives		(29	)		—			—			—			(29	)
Proceeds from issuance of common stock, net		—			—			986			—			986
Proceeds from issuance of preferred shares, net		—			—			486			—			486
Proceeds from issuance of long-term debt		2,760			—			7,175			(2,760	)		7,175
Funded letter of credit		—			—			350			—			350
Payment of deferred debt issuance costs		—			—			(164	)		—			(164	)
Payments for short and long-term debt		(2,735	)		(12	)		(1,876	)		—			(4,623	)

Net Cash Provided/(Used) by Financing Activities		(4	)		(12	)		6,947			(2,760	)		4,171
Effect of Exchange Rate Changes on Cash and Cash Equivalents		—			1			—			—			1
Change in Cash from Discontinued Operations		—			(17	)		—			—			(17	)

Net Increase/(Decrease) in Cash and Cash Equivalents		207			29			59			—			295
Cash and Cash Equivalents at Beginning of Period		(7	)		78			422			—			493

Cash and Cash Equivalents at End of Period	$	200		$	107		$	481		$	—		$	788


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

Note 17 — Subsequent Events

During May 2007, the Company plans to seek several amendments to its Senior Credit Facility. The amendments include:

	•		Lower pricing for NRG’s Term B loan and synthetic Letter of Credit facility;

	•		A provision that enables up to $150 million annually for the payment of a recurring cash dividend on the Company’s common stock;

	•		Reduction in the synthetic Letter of Credit facility from $1.5 billion to $1.3 billion;

	•		Ability to utilize a first lien position to support commercial hedges;

	•		Additional flexibility for RepoweringNRG projects; and

	•		A commitment from lenders that effectively converts one-third of existing Term B debt (approximately $1 billion in the aggregate) to a holding company level planned for later this year.

To improve the efficiency of its capital allocation, the Company is planning to implement a holding company structure in the second half of 2007. Under the planned structure:

	•		NRG will become a wholly-owned operating subsidiary, or Opco, of a newly created holding company, or Holdco, and the shareholders of the Company will become shareholders of Holdco;

	•		Holdco will borrow up to $1 billion in new Term B loan financing from its existing bank group; and

	•		Holdco will use the net proceeds to make a capital contribution to Opco, which Opco in turn will use for the prepayment of its Term B debt under the Senior Credit Facility.

Upon completion of the above, the Company’s restricted payments capacity under its unsecured indenture will increase by an amount equal to the capital contribution from Holdco to Opco, thereby allowing a more efficient allocation of capital within the Company. On May 1, 2007, the Company entered into a commitment with certain financial institutions to backstop the $1 billion financing planned for the Holdco level. Implementation of the Holdco structure described above is contingent upon a number of conditions being satisfied, including receiving certain regulatory approvals. While there can be no assurance that all of these conditions will be satisfied, the Company believes that the Holdco structure will be implemented by the end of 2007.

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

Introduction and Overview

NRG Energy, Inc., NRG, or the Company, is a wholesale power generation company with a significant presence in major competitive power markets in the United States. NRG is primarily engaged in the ownership, development, construction and operation of power generation facilities, the transacting in and trading of fuel and transportation services, and the trading of energy, capacity and related products in the United States and internationally. As of March 31, 2007, NRG had a total global portfolio of 191 active operating generation units at 49 power generation plants, with an aggregate generation capacity of approximately 24,025 MW. Within the United States, the Company has one of the largest and most diversified power generation portfolios in terms of geography, fuel-type and dispatch levels, with approximately 22,790 MW of generation capacity in 175 active generating units at 43 plants. These power generation facilities are primarily located in Texas (approximately 10,785 MW), and the Northeast (approximately 7,160 MW), South Central (approximately 2,850 MW), and the West (approximately 1,870 MW) regions of the United States, with approximately 125 MW of additional generation capacity from the Company’s thermal assets. NRG’s principal domestic power plants consist of a diversified mix of natural gas-, coal-, oil-fired and nuclear facilities, representing approximately 45%, 34%, 16% and 5% of the Company’s total domestic generation capacity, respectively. In addition, 15% of NRG’s domestic generating facilities have dual or multiple fuel capacity, which allows plants to dispatch with the lowest cost fuel option, and consist primarily of baseload, intermediate and peaking power generation facilities, which are referred to as the merit order, and also 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 diverse 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. In addition, NRG is pursuing opportunities to repower existing facilities and develop new generation capacity in markets in which NRG currently owns assets in an initiative referred to as RepowerinNRG. In connection with NRG’s acquisition of Padoma Wind Power LLC, the Company has and will continue to actively evaluate and potentially develop or construct domestic terrestrial wind projects as part of the RepoweringNRG program.

NRG’s 2006 Annual Report on Form 10-K includes a detailed discussion of various items impacting its business, results of operations, and financial condition. These include:

	•		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 section.

Critical accounting policies 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 revenue recognition and 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, and contingencies.

This discussion and analysis explains the general financial condition and the results of operations for NRG, including:

	•		factors which affect the business;
	•		earnings and costs in the periods presented;
	•		changes in earnings and costs between periods;
	•		sources of earnings;
	•		impact of these factors on NRG’s overall financial condition;
	•		expected future expenditures for capital projects; and
	•		expected sources of cash for further operations and capital expenditures.

As you read this discussion and analysis, refer to the consolidated statements of income which present the results of operations for the three months ended March 31, 2007 and 2006. NRG analyzes and explains the differences between periods in the specific line items of the consolidated statements of income.

NRG has organized the discussion and analysis as follows:

•

changes to the business environment during the period;

	•		results of operations beginning with an overview of NRG’s consolidated results, followed by a more detailed discussion of those results by major operating segment;
	•		financial condition, addressing liquidity, the sources and uses of cash, capital resources and commitments;
	•		known trends that will affect its results of operation and financial condition in the future.

Changes in Accounting Standards

See Note 1 to the condensed consolidated financial statements of this Form 10-Q as found in Item 1 for a discussion of recent accounting developments.

Environmental Matters

On April 2, 2007, in Environmental Defense v. Duke Energy, the U.S. Supreme Court overturned a decision by a lower court that had previously upheld Duke Energy’s modification of its coal plants as consistent with the USEPA’s PSD regulations. NRG has not relied upon the Duke Energy interpretation of the PSD regulations whenever the Company has performed modifications at its plants and thus does not expect any material adverse impact regarding NSR from the Supreme Court’s decision. Similarly, the Company has not relied upon the Duke Energy interpretation to support its repowering program.

The January 2007 court ruling on the appeal of the Phase II 316(b) water regulation created uncertainty for power plants that use once through cooling water. The regulation, for the most part, was sent back to EPA for reconsideration and expressly prohibited restoration. On March 20, 2007, the EPA issued a memo to Regional Administrators suspending the rule and directing them to rely on best professional judgment. Suspension of the rule is not expected to materially impact NRG plans, but could delay implementation.

Regulatory Matters

As an operator of power plants and a participant in the wholesale markets, NRG is subject to regulation by various federal and state government agencies. In addition, NRG is subject to the market rules, procedures, and protocols of the various ISO markets in which NRG participates. These wholesale power markets are subject to ongoing legislative and regulatory changes. In some of NRG’s regions, interested parties have advocated for material market design changes, including the elimination of a single clearing price mechanism, as well as proposals to re-regulate the markets or require divestiture by generating companies in order to reduce their market share. The Company cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on NRG’s business.

Northeast Region

New England - On April 26, 2007, the Company filed an RMR agreement for its Norwalk Power facility, Units 1 & 2, with FERC, seeking a June 19, 2007 effective date and an annual fixed revenue requirement of $38 million. This filing is in response to FERC’s order eliminating the Peaking Unit Safe Harbor, or PUSH, bidding mechanism effective June 19, 2007.

New York - On March 6, 2007, FERC rejected the NYISO’s proposed tariff revisions that would have imposed additional market power mitigation on the current owners of Consolidated Edison’s divested generation units in New York City, including NRG’s Arthur Kill and Astoria facilities. The proposed mitigation would have effectively lowered the capacity offer cap for those units from $105/kW-year to $82/kW-year. Although the specific proposal was rejected, FERC initiated an investigation to determine the justness and reasonableness of the NYISO’s in-city ICAP market, setting a refund effective date of May 12, 2007. FERC is expected to commence hearing procedures as settlement procedures have concluded. The result of this proceeding could adversely impact capacity revenues for NRG’s units in New York.

West Region

In November 2006, NRG was awarded a 260 MW PPA by Southern California Edison, or SCE, to repower Units 1-4 at the Company’s Long Beach Generating Station in Long Beach, California. On January 25, 2007, the CPUC issued its order approving the agreement and authorizing cost recovery by SCE. Intervenors sought rehearing, and the CPUC issued an order on April 19, 2007 denying the petition of two intervenors. These intervenors could appeal. NRG has reached a resolution with the remaining intervenor. Although the CPUC approval is not final and NRG may face other challenges, NRG is proceeding with the project.

Consolidated Results of Operations

The following table provides selected financial information for the Company for the three months ended March 31, 2007 and 2006:


	Three months ended March 31,
(In millions except otherwise noted)	2007			2006			Change %

Operating Revenues
Energy revenue	$	947		$	556			70	%
Capacity revenue		273			290			(6	)
Risk management activities		(43	)		52			NA
Contract amortization		52			44			18
Thermal revenue		41			38			8
Other revenues		40			63			(37	)

Total operating revenues		1,310			1,043			26

Operating Costs and Expenses
Cost of operations		784			659			19
Depreciation and amortization		161			118			36
General and administrative		86			57			51
Development costs		23			—			NA

Total operating costs and expenses		1,054			834			26
Gain on sale of assets		17			—			NA

Operating income		273			209			31
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates		13			21			(38	)
Write down of equity method investments		—			(3	)		NA
Other income, net		16			80			(80	)
Refinancing expenses		—			(178	)		NA
Interest expense		(181	)		(115	)		57

Total other expenses		(152	)		(195	)		(22	)
Income from Continuing Operations before income tax expense		121			14			764
Income tax expense/(benefit)		56			(1	)		NA

Income from Continuing Operations		65			15			333
Income from discontinued operations, net of income tax expense		—			11			NA

Net Income	$	65		$	26			150

Business Metrics
Average natural gas price — Henry Hub (S/MMbtu)		7.19			7.69			(7	)%

NA — Not Applicable

Consolidated Discussion:

Operating Revenues

Operating revenues increased by $267 million during the three months ended March 31, 2007, compared to 2006. This was primarily due to:

Energy revenues — energy revenues increased by $391 million during the three months ended March 31, 2007, compared to 2006:

•

Texas energy revenues increased by $361 million for the three months ended March 31, 2007, compared to 2006. Of this increase $217 million was due to the inclusion of three months activity in 2007 compared to two months in 2006, and $39 million is due to the Hedge Reset as average forward prices increased by approximately $12 per MWh for 2007 compared to 2006. The remaining increase was due to a reduction of the Power Utility Commission of Texas, or PUCT, auctioned capacity that is now being sold on the merchant market at higher prices. Prior to the Acquisition, PUCT regulations required that Texas sell 15% of its capacity by auction at reduced rates. In March 2006, the PUCT accepted NRG’s request to discontinue these auctions and such capacity is now being sold in the merchant market at higher prices.

•

Northeast energy revenues increased by approximately $49 million of which $24 million was due to an 11% increase in generation led by the region’s oil-fired assets whose generation increased by 176 thousand MWh compared to 2006 and $25 million was due to a 7% increase in average power prices. These increases were due to a relatively colder winter during 2007 compared to 2006 as demonstrated by a 12% increase in HDDs in the region.

Capacity revenues — capacity revenues decreased by $17 million during the three months ended March 31, 2007, compared to 2006, due to a decrease in the Texas capacity revenues that were partially offset by increases in capacity revenues in the Northeast and West regions:

	•		Texas — capacity revenues decreased by $73 million in the first quarter 2007 compared to 2006 due to a reduction of auction sales mandated by the PUCT in prior years as described above.
	•		Northeast — capacity revenues increased by $25 million - $12 million of the increase is from the NEPOOL assets and $12 million is from New York Rest of State assets. The NEPOOL assets benefited from the new LFRM market and transition capacity market, both introduced in the fourth quarter of 2006. During the three months ended March 31, 2007, capacity revenues increased by $9 million from the LFRM market and $7 million from transition capacity payments, offset by a reduction of $4 million due to the expiration of an RMR agreement for our Devon plant on December 31, 2006. New York Rest of State capacity prices increased by 174% during the first quarter of 2007 compared to 2006 as load requirement growth increased demand for capacity, coupled with the impact from the new capacity markets in NEPOOL which reduced exported supply into the New York market that further improved the supply/demand dynamics.
	•		West — capacity revenues increased by $26 million as its results were not consolidated during the three months ended March 31, 2006. These capacity revenues are comprised of new tolling agreements at the El Segundo and Encina plants that will expire in April 2008 and December 2009, respectively.

Contract amortization — revenues from contract amortization increased by $8 million during the three months ended March 31, 2007, compared to 2006, as a result of in-the-market power contracts acquired with Texas Genco LLC that were fully amortized in 2006. In-the-market power contracts are amortized as a reduction to revenues.

Other revenues — other revenues decreased by $23 million during the three months ended March 31, 2007 compared to 2006 due to the following factors:

	•		Sale of SO₂ allowances — net sales of emission allowances decreased by $53 million for the quarter ended March 31, 2007, compared to 2006. Due to increased generation and a decrease of approximately 59% in market prices, the Company reduced its activity in the sale of emission allowances.
	•		Physical sale of natural gas — with natural gas generation decreasing by 14%, the Company sold its excess natural gas to third parties increasing other revenues by approximately $19 million during the three months ended March 31, 2007, compared to 2006.
	•		Ancillary revenues — during the three months ended March 31, 2007, the Company’s revenues from ancillary services increased by approximately $8 million due to a change in strategy to actively provide ancillary services in the Texas region in lieu of merchant revenues.

Risk management activities — revenues from risk management activities include all derivative activity that does not qualify for hedge accounting as well as the ineffective portion associated with hedged transactions. Such revenues decreased by $95 million during the three months ended March 31, 2007, compared to 2006. The breakdown of changes by region are as follows:


	Three months ended March 31, 2007												Three months ended March 31, 2006
							South												South
(In millions)	Texas			Northeast			Central			Total			Texas ^(a)			Northeast			Central		Total

Net gains/(losses) on settled positions, or financial revenues	$	18		$	29		$	—		$	47		$	—		$	(1	)	$	4	$	3

Mark-to-market results
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges		(31	)		(26	)		—			(57	)		—			45			—		45
Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity		1			(9	)		(5	)		(13	)		—			(24	)		—		(24	)
Net unrealized gains/(losses) on open positions related to economic hedges		(10	)		(25	)		—			(35	)		(2	)		30			1		29
Net unrealized gains/(losses) on open positions related to trading activity		2			2			11			15			—			(1	)		—		(1	)

Subtotal mark-to-market results		(38	)		(58	)		6			(90	)		(2	)		50			1		49
Total derivative gain/(loss)	$	(20	)	$	(29	)	$	6		$	(43	)	$	(2	)	$	49		$	5	$	52

(a)

the period February 2, 2006 to March 31, 2006 only.

NRG’s first quarter 2007 loss was comprised of $90 million of mark-to-market losses offset by $47 million in settled gains, or financial revenue. Of the $90 million of mark-to-market losses, $57 million represents the reversal of mark-to-market gains recognized on economic hedges during 2006 and $13 million from the reversal of mark-to-market gains recognized on trading activity during 2006. Both of these gains ultimately settled as financial revenues during 2007. The $35 million loss from economic hedge positions is comprised of a $79 million decrease in value of forward sales of electricity and fuel due to unfavorable power and gas prices offset by a $44 million gain from hedge accounting ineffectiveness related to gas swaps in the Texas region due to a change in the correlation at March 31, 2007, between natural gas and power prices.

Since these hedging activities are intended to mitigate the risk of commodity price movements on revenues and cost of energy sold, the changes in such results should not be viewed in isolation, but rather taken together with the effects of pricing and cost changes on energy revenues (which are recorded net of financial instruments hedges that are afforded hedge accounting treatment) and cost of energy.

Cost of Operations

Cost of operations for the year ended March 31, 2007, increased by $125 million compared to 2006, but as a percentage of revenues it decreased from 63% in 2006 to 60% in 2007:

Cost of energy — cost of energy increased by approximately $52 million during the three month period ended March 31, 2007, compared to 2006. This increase is due to:

	•		Texas — although Texas results included an additional month’s expense of $96 million in 2007, this was offset by a $35 million reduction in purchased power during 2007 as compared to 2006 and a reduction in amortized fuel costs of $15 million during 2007 compared to 2006. During 2006, Texas purchased power due to forced outages at the Parish and Limestone plants. Amortized fuel costs decreased by $15 million due to changes in purchase price allocations that were finalized in the fourth quarter of 2006. In addition, coal expense decreased by approximately $6 million due to lower contractual rates for coal purchases.
	•		Northeast — Northeast expenses increased by $36 million due to an 11% increase in generation, resulting in $33 million of additional oil costs and $15 million of additional natural gas costs. This was offset by reduced emission allowance amortization expense of $8 million and lower coal expense of approximately $4 million. The change in emission amortization expense was due to the reduced value of emission allowances with the reduction in coal expense due to lower contractual rates on coal purchases.
	•		South Central — although South Central generation was relatively flat, cost of energy decreased by $9 million. Higher coal and transportation costs due to contractual rate increases resulted in a $7 million increase in fuel expense, while transmission costs increased by $4 million due to contractual increases in transmission rates; these increases were offset by lower purchased power of $19 million due to the increased reliance of satisfying contract load requirements with generation from the region’s Big Cajun II plant.

Other operating expenses — Other operating expenses increased by $73 million during the three month period ended March 31, 2007, compared to 2006. This increase was primarily due to:

	•		Acquisition of Texas and WCP — the results for the three months ended March 31, 2007, included $38 million of Texas expenses and $15 million of WCP expenses that were not included in the Company’s results in 2006.
	•		Planned outages — Operations and maintenance expense increased by $16 million during the two months ended March 31, 2007, compared to 2006 due to the planned refueling outage at STP and an acceleration of the W. A. Parish Unit 5 planned outage.
	•		Property taxes — property taxes increased by approximately $6 million due to the increase in assessed values of the Company’s assets following the acquisition of Texas Genco LLC in 2006.

Depreciation and Amortization

NRG’s depreciation and amortization expense for the three months ended March 31, 2007 increased by $43 million compared to 2006. This increase was primarily due to:

	o		Texas acquisition — the inclusion of Texas results for three months in 2007 compared to only two months in 2006 that resulted in an increase of approximately $38 million.
	o		Impact of new environmental legislation — Due to new and more restrictive environmental legislation, the useful life of certain types of pollution control equipment has been reduced. The company accelerated the depreciation of these types of equipment to reflect the remaining useful life, resulting in increased depreciation of approximately $3 million.

General and Administrative

NRG’s general and administrative, or G&A, costs for the three months ended March 31, 2007 increased by $29 million compared to 2006. This increase was primarily due to:

	o		Texas acquisition — the inclusion of Texas results for three months in 2007 compared to only two months in 2006 resulted in an increase of approximately $7 million.
	o		Wage and Benefit Costs — an increase in headcount, higher bonus accrual rates and related benefit costs resulted in a $17 million increase in G&A.
	o		Franchise tax — the Company’s Louisiana state franchise tax increased by approximately $6 million during the three months ended March 31, 2007, as compared to 2006. This is because the state of Louisiana franchise tax is assessed based on the Company’s total debt and equity that significantly increased following the acquisition of Texas Genco LLC.

Development Costs

NRG’s development costs were $23 million for the three months ended March 31, 2007. These costs were due to the Company’s RepoweringNRG projects:

	o		Texas — Costs to develop nuclear units 3 and 4 at STP accounted for approximately $17 million of the Company’s first quarter 2007 development costs.
	o		Other project — $5 million in development costs related to other RepoweringNRG project in the Northeast and West regions as well as certain wind projects.

Gain on Sale of Assets

NRG’s gain on sale of assets for the three months ended March 31, 2007 was approximately $17 million. On January 3, 2007, NRG completed the sale of the Company’s Red Bluff and Chowchilla II power plants resulting in a pre-tax gain of approximately $18 million.

Equity in Earnings of Unconsolidated Affiliates

NRG’s equity earnings from unconsolidated affiliates for the three months ended March 31, 2007 decreased by $8 million compared to 2006. This decrease was primarily due to:

	o		Sale of multiple equity investments — equity earnings of $5 million were earned in the three months ended March 31, 2006, from multiple affiliates that were either sold or subsequently consolidated, including: WCP, Rocky Road, James River and Latin American Fund.
	o		MIBRAG — equity earnings were $5 million less during 2007 compared to 2006 following reduced sales of coal. The reduction in sales is due to reduced demand from MIBRAG’s customers due to the warm winter in Germany this quarter and transmission difficulties experienced by one of its primary customers.

Other Income, Net

NRG’s other income for the three months ended March 31, 2007 decreased by $64 million compared to 2006. This decrease was primarily due to:

Non-cash settlement — during the first quarter 2006, NRG recorded approximately $67 million of other income associated with a settlement with an equipment manufacturer related to turbine purchase agreements entered into in 1999 and 2001. The

			settlement resulted in the reversal of accounts payable totaling $35 million resulting from the discharge of the previously recorded liability, and an adjustment to record the value of the equipment received to its fair value, resulting in income of approximately $32 million.
	o		Interest income — increased by approximately $2 million for the three months ended March 31, 2007 compared to 2006 due to higher market interest rates on deposits.

Interest Expense

NRG’s interest expense for the three months ended March 31, 2007 increased by $66 million compared to 2006. This increase is due to:

	o		Refinancing for the acquisition of Texas Genco LLC in February 2006 — the Company significantly increased its corporate debt facilities from approximately $2 billion as of December 31, 2005, to approximately $7 billion as of March 31, 2006. This increased interest expense for the three months ended March 31, 2007, by $37 million compared to 2006.
	o		Increase of $1.1 billion in debt for Hedge Reset — the Company issued $1.1 billion in Senior Notes due 2017 in November 2006 related to the Hedge Reset, which increased interest expense by $20 million for the three months ended March 31, 2007.
	o		Capital Allocation Program — the Company issued a total of $330 million of debt to fund Phase I of the Capital Allocation Program. This increased interest expense for the three months ended March 31, 2007 by $7 million compared to 2006.

In the first quarter 2006, NRG entered into interest rate swaps with the objective of fixing the interest rate on a portion of NRG’s new Senior Credit Facility. These swaps were designated as cash flow hedges under FAS 133, and the impact associated with ineffectiveness was immaterial to NRG financial results. For the three months ended March 31, 2007, NRG had deferred a loss of $7 million in other comprehensive income compared to deferred gains of $42 million in 2006.

Refinancing Expense

Refinancing expense decreased by $178 million during the three months ended March 31, 2007, compared to 2006 due to the refinancing of the Company’s corporate debt for the acquisition of Texas Genco LLC on February 2, 2006. During 2007, NRG did not refinance any debt.

Income Tax Expense

Income tax expense increased by $57 million during the three months ended March 31, 2007, compared to 2006. The effective tax rate was 46.3% and (7.1%) for the three months ended March 31, 2007 and 2006, respectively. The increase in tax expense was primarily due to increased profits and an increase in permanent differences:

	o		Increased profits — income before tax increased by $107 million during the three months ended March 31, 2007, compared to 2006, with a corresponding increase of approximately $42 million in tax expense.
	o		Permanent differences —

	•		Taxable dividends from foreign subsidiaries — in January 2007 the Company transferred the proceeds from the sale of its Flinders assets to the US creating additional tax expense of approximately $5 million.
	•		Non-deductible interest — interest expense from the stock buybacks from Phase I of the Company’s Capital Allocation Program increased tax expense by approximately $3 million.
	•		Lower tax rates in foreign jurisdictions — lower tax rates at the Company’s foreign locations reduced tax expense by $6 million during the three months ended March 31, 2007 compared to 2006.
	•		During the first quarter 2006, the Company distributed payments from its disputed claims reserve that reduced income tax expense by approximately $7 million.

The effective tax rate may vary from period to period depending on, among other factors, the geographic and business mix of earnings and losses and the creation of valuation allowances in accordance with SFAS 109. These factors and others, including the Company’s history of pre-tax earnings and losses, are taken into account in assessing the ability to realize deferred tax assets.

Income from Discontinued Operations, Net of Income Tax Expense

Income from discontinued operations decreased by $11 million during the three months ended March 31, 2007, compared to 2006 as all discontinued operations were disposed of in 2006. During 2006 the Company sold its Audrain, Flinders and Resource Recovery operations that were classified as discontinued operations, with $10 million due to the after tax gain from the sale of Audrain and $1 million due to the aggregated results of their remaining operations for the three month period ended March 31, 2006.

Business Segment Results

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 18-22 of NRG Energy, Inc’s. 2006 Annual Report on Form 10-K. First quarter 2007 results of operations are not comparable to the first quarter 2006 results of operations for the Texas region due to the acquisition of Texas Genco LLC on February 2, 2006.

Selected income statement data


(In millions except otherwise noted)
Three months ended March 31,	2007			2006 (a)			Change %

Operating Revenues
Energy revenue	$	563		$	202			179
Capacity revenue		92			165			(44	)
Risk management activities		(20	)		(2	)		900
Contract amortization		47			41			15
Other revenues		13			—			NA

Total operating revenues		695			406			71

Operating Costs and Expenses

Cost of energy		237			218			9
Other operating expenses		186			95			96
Depreciation and amortization		114			74			54
Operating Income	$	159		$	18			783

MWh sold (in thousands)		10,978			7,313			50
MWh generated (in thousands)		10,742			6,538			64
Business Metrics
Average on-peak market power prices ($/MWh)		56.95			55.35			3
Cooling Degree Days, or CDDs (b)		102			97			5
CDD’s 30 year rolling average		80			66			21
Heating Degree Days, or HDDs (b)		1,203			607			98
HDD’s 30 year rolling average		1,270			677			88

	(a)		For the period February 2, 2006 to March 31, 2006 only.
	(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

For the three months ended March 31, 2007, operating income increased by $141 million as compared to 2006. Of this increase, $68 million is due to the January 2007 results on 4.2 million MWh of generation. For the two months ended March 31, 2007, the Hedge Reset increased the region’s revenues by approximately $39 million as compared to 2006 as the average price of the underlying power contracts increased by $12 per MWh. Offsetting the Hedge Reset impact were increased development costs and higher maintenance expenses.

Operating Revenues

Total operating revenues from the Texas region increased by $289 million during the three months ended March 31, 2007, as compared to 2006, due to the following:

Energy revenues — energy revenues increased by $361 million for the three months ended March 31, 2007, compared to 2006. Of this increase, $217 million was due to the inclusion of three months activity in 2007 compared to two months in 2006, and $39 million was mainly due to the Hedge Reset as average forward prices increased by approximately $12 per MWh for 2007 compared to 2006. The remaining increase was due to a reduction of the Power Utility Commission of Texas, or PUCT,

		auctioned capacity that is now being sold on the merchant market at higher prices. Prior to the Acquisition, PUCT regulations required that Texas sell 15% of its capacity by auction at reduced rates. In March 2006, the PUCT accepted NRG’s request to discontinue these auctions and such capacity is now being sold in the merchant market at higher prices.
o		Capacity revenues — capacity revenues decreased by $73 million in the first quarter 2007 compared to 2006 due to reduction of auction sales mandated by the PUCT in prior years.
o		Contract amortization — revenues from contract amortization increased by $7 million during the three months ended March 31, 2007, compared to 2006, as a result of in-the-market power contracts acquired with Texas Genco LLC that were fully amortized in 2006. In-the-market power contracts are amortized as a reduction to revenues.
o		Other revenues — during the three months ended March 31, 2007, the Company’s revenues from ancillary services increased by approximately $10 million due to a change in strategy to actively provide ancillary services in the Texas region in lieu of merchant revenues.

Risk Management Activity — Total derivative loss for the quarter was $20 million, compared to a loss of $2 million in the first quarter of 2006, as the Company’s derivative activity increased during the second quarter of 2006. The derivative loss of $20 million is comprised of financial revenues of $18 million offset by mark-to-market losses of $38 million. Of these mark-to-market losses, $31 million was due to the roll-off of 2006 mark-to-market gains and $10 million was related to for open positions on forward hedges — a $54 million loss from forward contracted electric and gas sales offset by a $44 million gain in cash flow hedge ineffectiveness due to a decline in the correlation between natural gas and power prices.

Cost of Energy

Cost of energy for the Texas region increased by $19 million during the three months ended March 31, 2007, compared to 2006. This included an additional month’s expense of $96 million in 2007, without which cost of energy would have decreased by $77 million. This was due to:

	o		Purchased power — decreased by $35 million during 2007 as compared to 2006 due to forced outages at the region’s Parish and Limestone plants in 2006.
	o		Amortized fuel costs — decreased by approximately $15 million during 2007 as compared to 2006 due to changes in purchase price allocations that were finalized in the fourth quarter of 2006
	o		Coal expense — decreased by approximately $6 million due to lower contractual rates for coal purchases.

Other Operating Expenses

Other operating expenses for the Texas region increased by $91 million during the three months ended March 31, 2007 compared to 2006. This was due to:

	o		Texas acquisition — the inclusion of Texas results for three months in 2007 compared to only two months in 2006 that resulted in an increase of approximately $53 million, of which $32 million was related to operating and maintenance costs, $6 million was property taxes and $15 million was related to general and administrative expenses and corporate allocations.
	o		Planned outages — Operations and maintenance expense increased by $16 million during the two months ended March 31, 2007, compared to 2006 due to the planned refueling outage at STP and an acceleration of the W. A. Parish Unit 5 planned outage.
	o		Development costs — as part of RepoweringNRG, development costs totaled $18 million in the first quarter 2007. Of this amount, $17 million was incurred for developing nuclear Units 3 & 4 at STP.

Northeast Region

For a discussion of the business profile of the Northeast region, see pages 22-25 of NRG Energy, Inc’s. 2006 Annual Report on Form 10-K.

Selected income statement data


(In millions except otherwise noted)
Three months ended March 31,	2007			2006		Change %

Operating Revenues
Energy revenue	$	272		$	223		22	%
Capacity revenue		83			58		43
Risk management activities		(29	)		49		NA
Other revenues		16			62		(74	)

Total operating revenues		342			392		(13	)

Operating Costs and Expenses
Cost of energy		162			126		29
Other operating expenses		103			93		11
Depreciation and amortization		25			22		14
Operating Income	$	52		$	150		(65	)

MWh sold (in thousands)		3,614			3,261		11
MWh generated (in thousands)		3,614			3,261		11
Business Metrics
Average on-peak market power prices ($/MWh)		78.46			72.99		7
Cooling Degree Days, or CDDs(a)		—			—		—
CDD’s 30 year rolling average		—			—		—
Heating Degree Days, or HDDs(a)		3,071			2,741		12
HDD’s 30 year rolling average		3,094			3,094		—

(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 $98 million for the three months ended March 31, 2007, compared to 2006. This was due to:

	o		Lower operating revenues — of approximately $50 million primarily related to losses in risk management activities of $29 million and lower sales of emission allowances of approximately $61 million.
	o		Higher cost of energy — of approximately $36 million due to increased generation at the regions oil-fired and natural-gas-fired plants in New York City.
	o		Higher other operating expenses — of approximately $10 million due to higher wage and benefit rates as a result of merit increases and rising benefit costs, as well as higher major maintenance expense due to scheduled outage repairs.

Operating Revenues

Operating revenues decreased by $50 million for the three months ended March 31, 2007, compared to 2006, due to:

	o		Losses related to risk management activities — losses of approximately $29 million during 2007 compared to $49 million in gains in 2006. The $29 million loss includes a $58 million unrealized loss related to the changes in fair value of forward derivative positions not qualifying for hedge accounting treatment as compared to a $50 million gain in the same period in 2006 of which $26 million was related to economic hedges. This $58 million loss includes a $35 million loss from the roll-off in the quarter of forward positions existing at end of fiscal year 2006. Risk management activity results in the first quarter 2007 included $29 million in realized gains on settled power positions.
	o		Reduction in other revenues — of $46 million of which approximately $61 million was due to reduced activity in the trading of emission allowance following both an increase in generation and a 59% decrease in market prices offset by higher natural gas sales of approximately $19 million.

These were partially offset by:

	o		Higher energy revenues — of $49 million of which $24 million was due to an 11% increase in generation led by the region’s oil-fired assets whose generation increased by 176 thousand MWh compared to 2006 and $25 million was due to a 7% increase in average power prices. These increases were due to a relatively colder winter during 2007 compared to 2006 as demonstrated by a 12% increase in HDDs in the region.
	o		Higher capacity revenues — by $25 million - $12 million of the increase is from the NEPOOL assets and $12 million is from New York Rest of State assets. The NEPOOL assets benefited from the new LFRM market and transition capacity market, both introduced in the fourth quarter of 2006. During the three months ended March 31, 2007, capacity revenues increased by $9 million from the LFRM market and $7 million from transition capacity payments, offset by a reduction of $4 million due to the expiration of an RMR agreement for our Devon plant on December 31, 2006. New York Rest of State capacity prices increased by 174% during the first quarter of 2007 compared to 2006 as load requirement growth increased demand for capacity, coupled with the impact from the new capacity markets in NEPOOL which reduced exported supply into the New York market that further improved the supply/demand dynamics.

Cost of Energy

Cost of energy increased by $36 million for the three months ended March 31, 2007 compared to 2006, primarily due to:

	o		Higher oil costs — of approximately $33 million due to an 11% increase in generation of which 176 thousand MWh was at the region’s oil-fired plants.
	o		Higher natural gas costs — of approximately $15 million due to higher natural gas prices and transportation costs.

This was partially offset by:

	o		Lower emission amortization — of approximately $8 million in amortization expense due to a reduction in the value of the Company’s emission allowances.
	o		Lower coal costs — of $4 million due to lower average cost of generation from the region’s coal-fired assets as a result of lower average prices of purchased coal.

Other Operating Expenses

Other operating expenses increased by $10 million for the three months ended March 31, 2007 compared to 2006, primarily due to:

	o		Higher wage and benefit costs — of approximately $4 million due to higher wages and benefit rates as a result of merit increases and rising benefit costs as well as additional overtime.
	o		Higher major maintenance expense — of approximately $2 million due to increased outage repairs.
	o		Higher corporate allocations — of approximately $2 million.

South Central Region

For a discussion of the business profile of the South Central region, see pages 26-27 of NRG Energy, Inc’s. 2006 Annual Report on Form 10-K.

Selected income statement data


(In millions except otherwise noted)
Three months ended March 31,	2007		2006		Change %

Operating Revenues
Energy revenue	$	87	$	109		(20	)%
Capacity revenue		52		48		(8	)
Risk management activities		6		5		20
Contract amortization		5		4		25
Other revenues		—		6		NA

Total operating revenues		150		172		(13	)

Operating Costs and Expenses
Cost of energy		81		90		(10	)
Other operating expenses		30		22		36
Depreciation and amortization		17		16		6
Operating Income	$	23	$	44		(48	)

MWh sold (in thousands)		2,826		2,874		(2	)
MWh generated (in thousands)		2,708		2,800		(3	)
Business Metrics
Average on-peak market power prices ($/MWh)		57.62		54.05		7
Cooling Degree Days, or CDDs(a)		102		114		(11	)
CDD’s 30 year rolling average		80		80		—
Heating Degree Days, or HDDs(a)		1,203		946		27
HDD’s 30 year rolling average		1,270		1,270		—

(a)

Operating Income

Operating income for the South Central region declined by $21 million for the first quarter 2007 compared to the same period in 2006. Increased demand from the region’s load customers combined with lower availability of the region’s Big Cajun II coal plant reduced the MWh’s available for sale to the merchant market.

Operating Revenues

Operating revenues decreased by $22 million for the three months ended March 31, 2007, compared to 2006, due to:

	o		Lower merchant energy revenues — of approximately $38 million driven by increased demand from the region’s load customers combined with lower availability of the region’s Big Cajun II coal plant reduced the MWh’s available for sale to the merchant market.
	o		Lower emission sales — due to generation needs and a 59% reduction in market prices, the region did not monetize any of the region’s bank emission allowances during the first quarter ended 2007.

This decrease was offset by:

	o		Higher contract energy revenues — of approximately $17 million, due to higher demand from the region’s contract customers of approximately 343 thousand MWh following cooler weather during the first quarter 2007 as reflected by a 27% increase in HDDs compared to 2006.
	o		Higher capacity revenues — of $4 million due to a new summer peak set in August 2006 which increased cooperative contract rates.

Cost of Energy

Cost of energy decreased by $9 million for the three months ended March 31, 2007, compared to 2006, due to:

Lower purchased power — of approximately $19 million due to the increased reliance on tolling agreements and lower average prices.

This was offset by:

Higher coal and transportation costs — of approximately $7 million and higher transmission costs of approximately $4 million. These increases were due to higher unit and contractual rate increases.

Other Operating Expenses

Other operating expenses increased by $8 million for the three months ended March 31, 2007, compared to 2006. This was due to Louisiana state franchise tax that increased by approximately $6 million. This is because the state of Louisiana franchise tax is assessed based on the Company’s total debt and equity that significantly increased following the acquisition of Texas Genco LLC.

West Region

For a discussion of the business profile of the West region, see pages 28-29 of NRG Energy, Inc’s. 2006 Annual Report on Form 10-K.

Selected income statement data


(In millions except otherwise noted)
Three months ended March 31,	2007		2006 ^(b)			Change %

Operating Revenues
Energy revenue	$	1	$	—			NA
Capacity revenue		26		—			NA
Risk management activities		—		—			—
Other revenues		1		1			—

Total operating revenues		28		1			NA

Operating Costs and Expenses
Cost of energy		1		—			NA
Other operating expenses		20		3			567
Depreciation and amortization		—		—			—
Operating Income	$	7	$	(2	)		NA

MWh sold (in thousands)		45		294			(85	)
MWh generated (in thousands)		81		294			(72	)
Business Metrics
Average on-peak market power prices ($/MWh)		58.68		56.66			4
Cooling Degree Days, or CDDs(a)		2		—			NA
CDD’s 30 year rolling average		10		7			43
Heating Degree Days, or HDDs(a)		1,586		1,434			11
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.
	(b)		Does not include WCP results of operations.

Operating Income

Operating income increased by $9 million for the three months ended March 31, 2007, compared to 2006. This was due to:

Liquidity and Capital Resources

Liquidity Position

As of March 31, 2007, NRG’s liquidity was approximately $2.1 billion and included approximately $704 million of unrestricted and restricted cash. NRG’s liquidity also included $822 million of borrowing capacity under the Company’s revolving line of credit, and $546 million of availability under the Company’s letter of credit facility. As of December 31, 2006, NRG’s liquidity was approximately $2.2 billion and included approximately $839 million of unrestricted and restricted cash. NRG’s liquidity also included $855 million of borrowing capacity under the Company’s revolving credit facility, and $533 million of availability under the Company’s letter of credit facility.

Management believes that these amounts and cash flows from operations will be adequate to finance 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 steady debt to equity ratio in the range of 45-60%.

Capital Allocation Program

NRG continued Phase II of the Company’s Capital Allocation Program during the first quarter 2007 with the repurchase of an additional 1,500,000 shares of the Company’s common stock for approximately $103 million. NRG expects to complete Phase II of the Capital Allocation Program during 2007 with funds generated from operations of approximately $165 million.

Second Lien Structure

NRG has granted second priority liens to certain counterparties on substantially all of the Company’s assets in the United States in order to secure obligations, which are primarily long-term in nature under certain power sale agreements and related contracts. NRG uses the second lien structure to reduce the amount of cash collateral and letters of credit that it may otherwise be required to post from time to time to support its obligations under these agreements. Within the second lien structure, the Company can hedge up to 80% of its baseload capacity and 10% of its non-baseload assets with these counterparties. As of March 31, 2007 and April 27, 2007, the net discounted exposure on the agreements and hedges that were subject to the second lien structure was approximately $90 million and $193 million, respectively.

The following table summarizes the amount of MWs hedged against the Company’s baseload assets and as a percentage relative to the Company’s forecasted baseload capacity under the second lien structure as of April 27, 2007:


Equivalent Net Sales secured by Second Lien Structure^(a)	2007			2008			2009			2010			2011			2012

In MW		3,518			3,400			3,651			2,949			3,201			575
As a percentage of total forecasted baseload capacity		57	%		57	%		62	%		50	%		55	%		12	%


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

(b)		2007 MW value consists of May through December positions only.

Capital Expenditures

Capital expenditures were $107 million and $35 million for the three months ending March 31, 2007 and 2006, respectively, due to the following:

Texas — capital expenditures in the Texas region was approximately $64 million due to:

	•		STP - $38 million related to nuclear fuel and capitalized plant improvements
	•		Fossil plants — the remaining balance spent on low pressure turbine rotor replacement at the W.A. Parish and Limestone facilities, combustion system replacement at T.H. Wharton plant and repairs at the Jewett mine

Northeast — capital expenditures in the Northeast region was approximately $17 million due to:

	•		Huntley and Dunkirk — approximately $8 million was related to bag house emission projects at these two facilities.
	•		Other Northeast facilities — General plant improvements

West — capital expenditures in the West region was approximately $22 million due to the Long Beach Generating station repowering project.

The following table summarizes NRG’s capital expenditure forecast, by region, for the full year of 2007 of approximately $450 million, inclusive of the $107 million spend during the first quarter 2007 capital spend:


(In millions)	Maintenance		Environmental		Development		Total

Northeast	$	41	$	112	$	7	$	160
Texas		143		4		—		147
South Central		28		27		—		55
West		4		1		73		78
Other		10		—		—		10

Total	$	226	$	144	$	80	$	450
Capital expenditures through March 31, 2007		74		11		22		107

Remaining capital expenditures for 2007	$	152	$	133	$	58	$	343

NRG anticipates funding these capital project with funds generated from operating activities.

NOL’s, Deferred Tax Assets and Uncertain Tax Benefits

As of March 31, 2007, the Company has U.S. domestic net operating loss carryforwards of $70 million. In addition to this amount, the Company has $712 million of tax effected unrecognized tax benefits which relate primarily to net operating losses for tax return purposes which have been classified as capital loss carryforwards for financial statements purposes for which a full valuation allowance has been established. As a result of our tax position and based on current forecasts, future U.S. domestic income tax payments will be minimal through mid year 2009 as these unrecognized tax benefits will be utilized for tax return purposes.

However, as these positions remain uncertain, the Company may recognize a non current liability of up to $712 million until resolution with the related taxing authorities. As we move forward, the Company will continue to accrue for such uncertain tax benefits and regular income tax payments are contingent upon their final resolution.

Cash Flow Discussion

NRG obtains cash from operations, proceeds from the sale of certain assets and the proceeds from the issuance of debt, preferred stock and common stock. NRG uses these funds to finance operations, make interest payments, repurchase its common stock, service debt obligations, finance capital expenditures, and meet other cash and liquidity needs.

The following table reflects the changes in cash flows for the comparative years; all cash flow categories include the cash flows from both continuing operations and discontinued operations:


(In millions)
Three months ended March 31,	2007			2006

Net cash provided by operating activities	$	106		$	342
Net cash used in investing activities		(112	)		(4,202	)
Net cash provided/(used) by financing activities	$	(136	)	$	4,171

Net Cash Provided By Operating Activities

For the three months ended March 31, 2007, net cash provided by operating activities decreased by $236 million compared to the three months ended March 31, 2006. This was due to the following reasons:

	o		Due to the upward shift of the forward price curves, NRG’s cash collateral deposits in support of derivative contracts increased by $120 million for the three months ended March 31, 2007, compared to a decrease of $230 million for the three months ended March 31, 2006, a difference of $350 million. As of March 31, 2007, NRG had a net cash collateral on deposit of $66 million;
	o		NRG’s activity for the three months ended March 31, 2007, resulted in a decrease of $114 million in working capital compared to an increase in working capital for the three months ended March 31, 2006, of $15 million, a difference of $129 million. This was due to the following reasons:

	•		Capacity revenues related to PUCT mandated auctions are paid a month in advance, as a result of a reduction in such auctions, cash receipts decreased by $52 million during the three months ended March 31, 2007 compared to 2006.
	•		$32 million related to payment of property taxes in Texas paid in January 2007.
	•		$16 million of payments related to a large vesting of equity compensation compared to 2006.
	•		$31 million due to the receipt of trade receivables related to sales prior to the acquisition of Texas Genco LLC, were excluded from working capital as they were an increase to the purchase price.

Net Cash Provided By Investing Activities

For the three months ended March 31, 2007, net cash used in investing activities was approximately $4.1 billion less than the three months ended March 31, 2006. NRG’s decrease in use of cash was due to:

	o		During the first quarter 2006, NRG acquired Texas Genco LLC for approximately $6.2 billion that included the issuance of stock of $1.7 billion and a net cash payment of approximately $4.3 billion (net of cash on hand of $238 million);
	o		NRG’s capital expenditures increased by $72 million during the three months ended March 31, 2007, as compared to 2006, with the increase due to $38 million spent on nuclear fuel and capitalized improvements at the STP plant and $22 million for RepoweringNRG at the Company’s Long Beach facility.

Net Cash Provided/(Used) in Financing Activities

For the three months ended March 31, 2007, net cash from financing activities decreased by approximately $4.3 billion, as compared to 2006. The decrease was primarily due to the financing activities related to the purchase of Texas Genco LLC during 2006:

During the first quarter 2006, NRG acquired Texas Genco LLC. As part of the acquisition, NRG refinanced the Company’s outstanding debt as well as Texas Genco LLC’s outstanding debt, and also issued new debt, preferred stock and common stock to fund the acquisition:

	•		Total debt repayments were $4.6 billion — $1.9 billion from NRG debt and $2.7 billion of Texas Genco LLC debt;
	•		Total proceeds from debt issued was $7.2 billion — $3.6 billion of unsecured notes and $3.6 billion for a senior secured facility, including a $1.0 billion Revolving Credit Facility, and a $1.0 billion synthetic Letter of Credit Facility;
	•		Total proceeds from stock issued of approximately $1.5 billion — net proceeds of $986 million from issuing approximately 21 million shares of common stock and net proceeds of $486 million from issuing 2 million shares of the Company’s 5.75% Preferred Stock.

In 2006, NRG initiated a Capital Allocation Program executed in two phases. As part of Phase II, NRG repurchased an additional 1,500,000 shares of the Company’s common stock for approximately $103 million during the first quarter 2007.

New and On-going Company Initiatives

Comprehensive Capital Allocation Plan

The Company’s capital allocation strategy includes (i) the repayment of debt, (ii) the return of capital to shareholders, and (iii) the investment of capital into the business. With the establishment of the Company’s longer-dated hedge profile, the variability of gross margins has been substantially reduced. Accordingly, for each of the planned debt repayment and return of capital to shareholders, the Company is migrating towards a structure that provides for both a fixed and a variable component. In November 2006, the Company modified its Senior Credit Facility to include, among other things, an annual mandatory prepayment based on the current year’s excess cash flow — the fixed component — while retaining the right to voluntarily prepay all or a portion of the Company’s outstanding Term B loan at no penalty — the variable component. The Company also has announced plans for a Comprehensive Capital Allocation Plan that will support a similar fixed and variable structure for the return of capital to shareholders. If implemented, this plan will provide the Company with the ability (i) to initiate an annual cash dividend — the fixed component — and (ii) to continue the Company’s historical program of common share repurchases — the variable component. The Company’s total annual targeted return of capital to shareholders is expected to be approximately 3% of NRG’s current market capitalization. Once completed, the Company expects to commence payment of quarterly cash dividends in the first quarter 2008, subject to approval by the Company’s Board of Directors and other conditions including availability of cash resources. In addition, the Company plans to complete Phase II of its Capital Allocation Program announced in November 2006 with the repurchase of approximately $165 million of common stock during 2007.

During May 2007, the Company plans to seek several amendments to its Senior Credit Facility. The amendments include:

	•		Lower pricing for NRG’s Term B loan and synthetic Letter of Credit facility;

	•		A provision that enables up to $150 million annually for the payment of a recurring cash dividend on the Company’s common stock;

	•		Reduction in the synthetic Letter of Credit facility from $1.5 billion to $1.3 billion;

	•		Ability to utilize a first lien position to support commercial hedges;

	•		Additional flexibility for RepoweringNRG projects; and

	•		A commitment from lenders that effectively converts one-third of existing Term B debt (approximately $1 billion in the aggregate) to a holding company level planned for later this year.

To improve the efficiency of its capital allocation, the Company is planning to implement a holding company structure in the second half of 2007. Under the planned structure:

	•		NRG will become a wholly-owned operating subsidiary, or Opco, of a newly created holding company, or Holdco, and the shareholders of the Company will become shareholders of Holdco;

	•		Holdco will borrow up to $1 billion in new Term B loan financing from its existing bank group; and

	•		Holdco will use the net proceeds to make a capital contribution to Opco, which Opco in turn will use for the prepayment of its Term B debt under the existing Senior Credit Facility.

RepoweringNRG

Plants under Development

Most of the originally planned RepoweringNRG projects continue in the development phase. During the first quarter 2007, many RepoweringNRG projects made progress in permitting, site planning and other critical development activities. Other RepoweringNRG projects, including projects in Connecticut and in Delaware are less likely to move forward as they have not been successful to date in winning off-take mandates offered as part of requests for proposals sponsored by these states.

Plants under Construction

260 MW of repowered gas-fueled capacity at NRG’s Long Beach Generating Station remains on schedule to be online by August 1, 2007 to support the anticipated summer peak on the Southern California Edison and California Independent System Operator systems. Total capital expenditures for the project are expected to be approximately $73 million, with $22 million incurred during the first quarter 2007. In addition to the Long Beach project, the Company is proceeding with the repowering project at the Cos Cob site in Connecticut. This project will add 40 MW of peaking capacity at a cost of $18 million.

Development Costs

During the first quarter 2007, NRG incurred approximately $23 million in costs associated with development efforts across all segments of the Company, but predominately in Texas to support the planned expansion of the STP nuclear generating station as the Company prepares for the submission of a combined operating license application.

Stock Dividend

On April 25, 2007, NRG’s Board of Directors approved a two-for-one stock split of the Company’s outstanding shares of common stock to be effected in the form of a stock dividend. The stock split will entitle each stockholder of record at the close of business on May 22, 2007 to receive one additional share for every outstanding share of common stock held. The additional shares resulting from the stock split are expected to be distributed by the Company’s transfer agent on or about May 31, 2007. Upon the completion of the stock split, NRG will have approximately 242 million shares of common stock outstanding.

Off-Balance Sheet Arrangements

Obligations Under Certain Guarantee Contracts

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

Retained or Contingent Interests

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

Derivative Instrument obligations

On August 11, 2005, NRG issued 3.625% Preferred Stock that included a conversion feature which is considered a derivative per FAS 133, as amended. Although it is considered a derivative, it is exempt from derivative accounting as it is excluded from the scope pursuant to paragraph 11(a) of FAS 133. As of March 31, 2007, based on the Company’s stock price, the value of the payment for this embedded derivative would have been approximately $49 million.

On October 13, 2006, NRG through its unrestricted wholly-owned subsidiaries NRG Common Stock Fund I, or CSF I, issued notes and preferred interests to a unit of Credit Suisse for the repurchase of NRG’s common stock. Included in the contract was a conversion feature which is considered a derivative per FAS 133, as amended. Although it is considered a derivative, it is exempt from derivative accounting as it is excluded from the scope pursuant to paragraph 11(a) of FAS 133. As of March 31, 2007, based on the Company’s stock price, the value of the payment for this embedded derivative would have been approximately $24 million.

Obligations Arising Out of a Variable Interest in an Unconsolidated Entity

Variable interest in Equity investments — As of March 31, 2007, NRG had not entered into any financing structure that was designed to be off-balance sheet that would create liquidity, financing or incremental market risk or credit risk to the Company. However, 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. NRG’s pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $146 million as of March 31, 2007. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG.

Synthetic Letter of Credit Facility and Revolver Facility — Under NRG’s Amended Senior Credit Facility NRG entered into on November 21, 2006, the Company has a $1.5 billion synthetic Letter of Credit Facility that is unfunded by NRG, and a $1 billion senior Revolving Credit Facility. The synthetic Letter of Credit Facility is secured by a $1.5 billion cash collateral deposit, held by Deutsche Bank AG, New York Branch, as the Issuing Bank. Under the synthetic Letter of Credit Facility, NRG is allowed to issue letters of credit to support the Company’s obligations under commodity hedging or power purchase arrangements. In addition, NRG can issue up to $300 million in unfunded letters of credit under the Company’s Revolving Credit Facility for ongoing working capital requirements and for general corporate purposes, including acquisitions that are permitted under the Senior Credit Facility. In addition, NRG is permitted to issue additional letters of credit up to $700 million under the Senior Credit Facility through another financial institution.

As of March 31, 2007, the Company had issued $954 million in letters of credit under the Letter of Credit Facility. In addition, as of March 31, 2007, the Company had issued $178 million in revolver letters of credit, a portion of which supports non-commercial letter of credit obligations.

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, 2006. Also see Note 12 to the condensed consolidated financial statements of this Form 10-Q for a discussion of new commitments and contingencies that also include contractual obligations and commercial commitments that occurred during the first quarter 2007.

Critical Accounting Policies and Estimates and Changes in Accounting Standards

NRG’s discussion and analysis of the financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. 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, 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 also may 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.

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 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, volatility in commodities, and correlations between various commodities, such as natural gas, electricity, coal and oil. 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.

As part of NRG’s overall portfolio, NRG manages the commodity price risk of the Company’s merchant generation operations by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted sales of electricity and purchases of fuel. These instruments include forward purchase and sale contracts, futures and option contracts traded on the New York Mercantile Exchange, and swaps and options traded in the over-the-counter financial markets. The portion of forecasted transactions hedged may vary based upon management’s assessment of market, weather, operation 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 commodity and derivative contracts held and sold. These estimates consider various factors, including closing exchange and over-the-counter price quotations, time value, volatility factors and credit exposure. 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 sensitivity of the Company’s portfolio to potential changes in market prices using Value at Risk, or VAR. VAR is a statistical model that attempts to predict risk of loss based on market price volatility. Currently, the company estimates VAR using a Monte Carlo simulation based methodology. NRG’s total portfolio includes mark-to-market and non mark-to-market energy assets and liabilities.

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: (1) a lognormal distribution of price returns, (2) one-day holding period, (3) a 95% confidence interval, (4) a rolling 24-month forward looking period, and (5) market implied price volatilities and historical price correlations.

As of March 31, 2007, 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 $22 million.

The following table summarizes average, maximum and minimum VAR for NRG for the three months ended March 31, 2007 and 2006. VAR for the three months ended March 31, 2006 does not include Texas since it was not integrated with the consolidated NRG portfolio.


VAR	2007		2006

As of March 31,	$	22	$	30
Average		26		33
Maximum		34		38
Minimum		22		27

Due to the inherent limitations of statistical measures such as VAR, the relative immaturity 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 of the potential loss of financial derivative 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 financial derivative instruments calculated using the diversified VAR model as of March 31, 2007 for the entire term of these instruments entered into for both asset management and trading was approximately $27 million.

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.

In January 2006, the Company entered into a series of new interest rate swaps. These interest rate swaps became effective on February 15, 2006 and are intended to hedge the risk associated with floating interest rates. For each of the interest rate swaps, NRG pays its counterparty the equivalent of a fixed interest payment on a predetermined notional value, and NRG receives the equivalent of a floating interest payment based on 3-month LIBOR rate calculated on the same notional value. All interest rate swap payments by NRG and its counterparties are made quarterly, and the LIBOR is determined in advance of each interest period. While the notional value of each of the swaps does not vary over time, the swaps are designed to mature sequentially. The total notional amount of these swaps as of April 27, 2007 was $2.0 billion.

As of March 31, 2007, the Company had various interest rate swap agreements with notional amounts totaling approximately $2.7 billion. If the swaps had been discontinued on March 31, 2007, the Company would have owed the counter-parties approximately $18 million. Based on the investment grade rating of the counter-parties, NRG believes that the Company’s exposure to credit risk due to nonperformance by the counter-parties to the hedging contracts is insignificant.

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, 2007, a 100 basis point change in interest rates would result in a $15 million change in interest expense on a rolling twelve month basis.

As of March 31, 2007, the fair value and the carrying amount of the Company’s long-term debt was $8.9 billion and $8.8 billion, respectively. NRG estimates that a 1% decrease in market interest rates would have increased the fair value of the Company’s long-term debt by $530 million.

Currency Exchange Risk

NRG expects to continue to be subject to currency risks associated with foreign denominated distributions from the Company’s international investments. In the normal course of business, NRG may receive distributions denominated in the Euro, Australian Dollar and the Brazilian Real. NRG has historically engaged in a strategy of hedging foreign denominated cash flows through a program of matching currency inflows and outflows, and to the extent required, fixing the U.S. Dollar equivalent of net foreign

denominated distributions with currency forward and swap agreements with highly credit worthy financial institutions. The Company would expect to enter into similar transactions in the future if management deems it to be appropriate.

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.

Based on a sensitivity analysis, a $1 per MWh increase or increase in electricity prices across the term of the marginable contracts would cause a change in margin collateral outstanding of approximately $55 million as of March 31, 2007. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of March 31, 2007.

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. The Company monitors and manages the credit risk of NRG and its subsidiaries through credit policies which include (i) an established credit approval process, (ii) a daily monitoring of counter-party 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 has credit protection within various agreements to call on additional collateral support if and when necessary. As of March 31, 2007, NRG held collateral support of approximately $292 million from counterparties.

A portion of NRG’s credit risk is related to transactions that are recorded in the Company’s consolidated Balance Sheet. These transactions primarily consist of open positions from the Company’s marketing and risk management operation that are accounted for using mark-to-market accounting, as well as amounts owed by counterparties for transactions that settled but have not yet been paid.

The following table highlights the credit quality and exposures related to these activities as of March 31, 2007:


	Exposure
(In millions, except ratios)	Before						Net
Credit Exposure	Collateral			Collateral			Exposure

Investment grade	$	1,200		$	347		$	853
Non-investment grade		73			51			22
Not rated		172			20			152

Total	$	1,445		$	418		$	1,027

Investment grade		83	%		83	%		83	%
Non-investment grade		5			12			2
Not rated		12	%		5	%		15	%

Additionally, the Company has concentrations of suppliers and customers among coal suppliers, electric utilities, energy marketing and trading companies and regional transmission operators. These concentrations of counterparties may impact NRG’s overall exposure to credit risk, either positively or negatively, in that counterparties may be similarly affected by changes in economic, regulatory and other conditions.

NRG’s exposure to significant counterparties greater than 10% of the net exposure of approximately $1 billion was approximately $622 million as of March 31, 2007. NRG does not anticipate any material adverse effect on the Company’s financial position or results of operations as a result of nonperformance by any of NRG’s counterparties.

Fair Value of Derivative Instruments

NRG may enter into long-term power sales contracts, fuel purchase contracts and other energy-related financial instruments to

mitigate variability in earnings due to fluctuations in spot market prices, to hedge fuel requirements at generation facilities and protect fuel inventories. 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 include contracts entered into to profit from market price changes as opposed to hedging an exposure, and are subject to limits in accordance with 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. These trading activities are a complement to NRG’s energy marketing portfolio.

The tables below disclose the activities that include non-exchange traded contracts accounted for at fair value. Specifically, these tables disaggregate realized and unrealized changes in fair value; identify changes in fair value attributable to changes in valuation techniques; disaggregate estimated fair values at March 31, 2007, based on whether fair values are determined by quoted market prices or more subjective means; and indicate the maturities of contracts at March 31, 2007:


Derivative Activity Gains/(Losses)	(In millions)

Fair value of contracts at December 31, 2006	$	354
Contracts realized or otherwise settled during the period		(28	)
Changes in fair value		(527	)

Fair value of contracts at March 31, 2007	$	(201	)


	Fair Value of Contracts as of March 31, 2007
	Maturity									Maturity
	Less than			Maturity			Maturity			in excess			Total Fair
Sources of Fair Value Gains/(Losses) (In millions)	1 Year			1-3 Years			4-5 Years			of 5 Years			Value

Prices actively quoted	$	(45	)	$	2		$	—		$	—		$	(43	)
Prices provided by other external sources		74			(51	)		(144	)		(37	)		(158	)
Prices provided by models and other valuation methods		1			(1	)		—			—			—

Total	$	30		$	(50	)	$	(144	)	$	(37	)	$	(201	)

ITEM 4 — CONTROLS AND PROCEDURES

Under the supervision and with the participation of Company’s management, including the principal executive officer, principal financial officer and principal accounting officer, NRG conducted an evaluation of the Company’s disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended. Based on this evaluation, NRG’s principal executive officer, principal financial officer and principal accounting officer concluded that the Company’s disclosure controls and procedures were effective as of the end of the period covered by this Quarterly Report. There have been no changes in the Company’s internal control over financial reporting during the quarter ended March 31, 2007 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1 — LEGAL PROCEEDINGS

For a discussion of material legal proceedings in which NRG was involved through March 31, 2007, see Note 12 to the condensed consolidated financial statements of this Form 10-Q.

ITEM 1A — RISK FACTORS

Information regarding risk factors appears in Part II, Item 1A, Risk Factors in NRG Energy, Inc.’s 2006 Annual Report on Form 10-K for the fiscal year ended December 31, 2006. Due to recent significant events at NRG, the following risk factor has been identified:

The Company may not have sufficient available cash to pay cash dividends each quarter.

NRG has never paid a cash dividend and has not had a policy with regard to the payment of cash dividends with respect to its common stock. In April 2007, the Company’s Board of Directors declared its intention to begin paying quarterly cash dividends to holders of NRG common stock, beginning in the first quarter 2008. The payment of cash dividends in the future will depend on a number of factors, including, NRG’s future financial performance, the Company’s available cash resources and the cash requirements of its business, state corporate law restrictions and, possibly the consents of third parties, such as the lenders under the Company’s Senior Credit Facility. In addition, the payment of each cash dividend and the amount of such dividends are subject to approval by the Company’s Board of Directors. As a result, there can be no assurance that NRG will implement its plans with regards to the payment of quarterly cash dividends.

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

Item 2(c) — Purchase of Equity securities by NRG


					Total number of shares		Dollar value of
					purchased as part of		shares that may be
	Total number of		Average price		publicly announced		purchased under the
For the period ended April 27, 2007	shares purchased		paid per share		plans or programs		plans or programs

January 1 — January 31		—	$	—		—	$	—
February 1 — February 28		—		—		—		—
March 1 — March 31		1,500,000		68.74		1,500,000		165,160,714

First Quarter Total		1,500,000		68.74		1,500,000

April 1 — April 27, 2007		—		—		—		—

Year-to-date		1,500,000	$	68.74		1,500,000	$	165,160,714

ITEM 3 — DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4 — SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

ITEM 5 — OTHER INFORMATION

None.

ITEM 6 — EXHIBITS

Exhibits



10.1*		Amended and Restated NRG Energy, Inc. Long-Term Incentive Plan, dated April 25, 2007, filed herewith.

10.2*		NRG Energy, Inc. Executive and Key Management Change-in-Control and General Severance Agreement, dated April 25, 2007, filed herewith.

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 Controller pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.

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


*		Exhibit relates to compensation arrangements.

SIGNATURES

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


		NRG ENERGY, INC. (Registrant)

		/s/ DAVID W. CRANE

		David W. Crane,
		Chief Executive Officer

		/s/ ROBERT C. FLEXON

		Robert C. Flexon,
		Chief Financial Officer
		(Principal Financial Officer)

		/s/ CAROLYN J. BURKE

		Carolyn J. Burke,
		Controller
Date: May 2, 2007		(Principal Accounting Officer)

EXHIBIT INDEX

Exhibits



10.1*		Amended and Restated NRG Energy, Inc. Long-Term Incentive Plan, dated April 25, 2007, filed herewith.

10.2*		NRG Energy, Inc. Executive and Key Management Change-in-Control and General Severance Agreement, dated April 25, 2007, filed herewith.

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 Controller pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.

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


*		Exhibit relates to compensation arrangements.