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, 2006		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  R  No  £

     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  R  Accelerated filer  £  Non-accelerated filer £

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

Yes  £  No  R

     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  R  No  £

     As of May 5, 2006, there were 136,976,099 shares of common stock outstanding.

 

 

TABLE OF CONTENTS

Index

		Page No.
Cautionary Statement Regarding Forward Looking Information			3
Glossary of Terms			4
Part I — FINANCIAL INFORMATION			6
Item 1 — Condensed Consolidated Financial Statements and Notes			6
Item 2 — Management’s Discussion and Analysis of Financial Condition and Results of Operations			44
Item 3 — Quantitative and Qualitative Disclosures About Market Risk			61
Item 4 — Controls and Procedures			64
Part II — OTHER INFORMATION			65
Item 1 — Legal Proceedings			65
Item 1A — Risk Factors			65
Item 2 — Unregistered Sales of Equity Securities and Use of Proceeds			65
Item 3 — Defaults Upon Senior Securities			65
Item 4 — Submission of Matters to a Vote of Security Holders			65
Item 5 — Other Information			65
Item 6 — Exhibits			65
SIGNATURES			66
Exhibit Index			67
EX-31.1: CERTIFICATION
EX-31.2: CERTIFICATION
EX-31.3: CERTIFICATION
EX-32: CERTIFICATIONS

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 Securities 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 our 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 statement. These factors, risks and uncertainties include the factors described under Risks Related to NRG Energy, Inc. in 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 or other raw materials;
	•		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 in 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 we 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;
	•		Our ability to operate our businesses efficiently, manage capital expenditures and costs tightly (including general and administrative expenses), and generate earnings and cash flow from our asset-based businesses in relation to our debt and other obligations;
	•		Our potential inability to enter into contracts to sell power and procure fuel on terms and prices acceptable to us;
	•		The liquidity and competitiveness of wholesale markets for energy commodities;
	•		Government regulation, including compliance with regulatory requirements and changes in market rules, rates, and tariffs and environmental laws;
	•		Price mitigation strategies and other market structures employed by independent system operators, or ISOs, or regional transmission organizations, that result in a failure to adequately compensate our generation units for all of their costs;
	•		Our ability to borrow additional funds and access capital markets, as well as our substantial indebtedness and the possibility that we may incur additional indebtedness going forward;
	•		The success of the business following the acquisition of Texas Genco LLC and West Coast Power, LLC;
	•		Lack of comparable financial data as the results of Texas Genco LLC are not reflected in prior period results; and
	•		Operating and financial restrictions placed on us contained in the indentures governing our 7.25% and 7.375% unsecured senior notes due 2014 and 2016, respectively, our senior secured credit facility and in debt and other agreements of certain of our subsidiaries and project affiliates generally.

     Forward-looking statements speak only as of the date they were made, and we undertake 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 our 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 NRG Texas
Acquisition Agreement		Acquisition Agreement dated September 30, 2005 underlying the February 2, 2006 acquisition of Texas Genco LLC, now referred to as NRG Texas
APB 18		Accounting Principles Board Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.”
BTA		Best Technology Available
BTU		British Thermal Unit
CAA		Clean Air Act
CAIR		Clean Air Interstate Rule
Cal ISO		California Independent System Operator.
CDWR		California Department of Water Resources
CERCLA		Comprehensive Environmental Response, Compensation and Liability Act
CL&P		Connecticut Light & Power
CO (2)		Carbon dioxide
CPUC		California Public Utilities Commission,
CTDEP		Connecticut Department of Environmental Protection
CWA		Clean Water Act
DNREC		Delaware Department of Natural Resources and Environmental Control
EFORd		Equivalent demand forced outage rate
EITF 02-3		Emerging Issues Task Force 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”
EPA		Environmental Protection Agency
ERCOT		Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas
FASB		Financial Accountings Standards Board
FERC		Federal Energy Regulatory Commission
FF-ACI		Fabric Filter with Activated Carbon Injection
FGD		Flue Gas Desulphurization
FIN 47		Financial Accounting Standards Board Interpretation No. 47
FIP		Federal Implementation Plan
Fresh Start		Reporting requirements as defined by SOP 90-7
GHG		Greenhouse Gases
IGCC		Integrated Gasification Combined Cycle
ISO		Independent System Operator, also referred to as regional transmission organizations, or RTO
ISO-NE		ISO New England, Inc.
LIBOR		London Inter-Bank Offered Rate
LNB/OFA		Low NOx Burner with Over Fire Air
MDE		Maryland Department of the Environment
MWh		Saleable megawatt hours net of internal/parasitic load megawatt-hours
NAAQS		National Ambient Air Quality Standards
NiMo		Niagara Mohawk Power Corporation
NOx		Nitrogen oxides
NOL		Net operating loss
NQSO		Non-qualified stock option
NRC		United States Nuclear Regulatory Commission
NYISO		New York Independent System Operator
NYSDEC		New York Department of Environmental Conservation
OCI		Other Comprehensive Income
OTC		Ozone Transport Commission
PJM		PJM Interconnection, LLC
PJM Market		The wholesale and retail electric market operated by PJM primarily in all or parts of Delaware, the District of Columbia, Illinois, Maryland, New Jersey, Ohio, Pennsylvania, Virginia and West Virginia
PM (2.5)		Fine particulate matter
PUCT		Public Utility Commission of Texas

Powder River Basin, or PRB Coal		Coal produced in the northeastern Wyoming and southeastern Montana, which has low sulfur content
RCRA		Resource Conservation and Recovery Act
RECLAIM		Regional Clean Air Incentives Market
RGGI		Regional Greenhouse Gas Initiative
RMR		Reliability must-run
RTC		RECLAIM Trading Credit
SCAQMD		South Coast Air Quality Management District
SCR		Selective Catalytic Reduction
SDG&E		San Diego Gas & Electric
SEC		United States Securities and Exchange Commission
SERC		Southeastern Electric Reliability Council/ Entergy
SFAS		Statement of Financial Accounting Standards issued by the FASB
SFAS 109		SFAS No. 109, “Accounting for Income Taxes”
SFAS 123R		SFAS No. 123 (revised 2004), “Share-Based Payment”
SFAS 133		SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS 141		SFAS No. 141, “Business Combinations”
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”
SIP		State Implementation Plan
SO2		Sulfur dioxide
SOP 90-7		Statement of Position 90-7 “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code”
STP		South Texas Project — NRG Texas’s nuclear generating facility located in Bay City, TX of which we own a 44% interest
NRG Texas		Texas Genco LLC
US		United States of America
USEPA		US Environmental Protection Agency
US GAAP		Accounting principles generally accepted in the US
VCP		Voluntary Clean-up Program
WCP		WCP (Generation) Holdings, Inc.

PART I — FINANCIAL INFORMATION

Item 1 — Condensed Consolidated Financial Statements and Notes

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

		Three Months Ended
		March 31,				March 31,
		2006				2005
		(In millions, except per
		share amounts)
Operating Revenues
Revenues from majority-owned operations		$	1,144			$	597
Operating Costs and Expenses
Cost of majority-owned operations			743				452
Depreciation and amortization			125				48
General, administrative and development			61				50
Corporate relocation charges			—				3
Total operating costs and expenses			929				553
Operating Income			215				44
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates			21				37
Write downs and losses on sales of equity method investments			(3	)			—
Other income, net			81				26
Refinancing expenses			(178	)			(25	)
Interest expense			(118	)			(55	)
Total other expense			(197	)			(17	)
Income From Continuing Operations Before Income Taxes			18				27
Income Tax Expense			—				5
Income From Continuing Operations			18				22
Gain From Discontinued Operations, net of Income Taxes			8				1
Net Income			26				23
Dividends for Preferred Shares			10				4
Income Available for Common Stockholders		$	16			$	19
Weighted Average Number of Common Shares Outstanding — Basic			117				87
Income From Continuing Operations per Weighted Average Common Share — Basic		$	0.06			$	0.20
Gain From Discontinued Operations per Weighted Average Common Share — Basic			0.07				0.01
Net Income per Weighted Average Common Share — Basic		$	0.13			$	0.21
Weighted Average Number of Common Shares Outstanding — Diluted			119				88
Income From Continuing Operations per Weighted Average Common Share — Diluted		$	0.06			$	0.20
Gain From Discontinued Operations per Weighted Average Common Share — Diluted			0.07				0.01
Net Income per Weighted Average Common Share — Diluted		$	0.13			$	0.21

See notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS — (Unaudited)

		March 31,				December 31,
		2006				2005
		(unaudited)
		(In millions, except shares and par value)
ASSETS
Current Assets
Cash and cash equivalents		$	818			$	506
Restricted cash			67				64
Accounts receivable, less allowance for doubtful accounts of $2 and $2			426				284
Inventory			412				260
Derivative instruments valuation			267				404
Collateral on deposit in support of energy risk management activities			251				438
Deferred income taxes			3				4
Prepayments and other current assets			202				193
Current assets — held for sale			11				43
Current assets — discontinued operations			—				1
Total current assets			2,457				2,197
Property, plant and equipment, net of accumulated depreciation of $520 and $392			11,452				3,039
Other Assets
Equity investments in affiliates			316				603
Notes receivable, less current portion			462				458
Goodwill – Preliminary			2,748				—
Intangible assets, net of accumulated amortization of $110 and $79			1,420				257
Nuclear decommissioning trust			320				—
Derivative instruments valuation			58				22
Deferred income taxes			27				26
Other non-current assets			247				475
Non-current assets — discontinued operations			—				354
Total other assets			5,598				2,195
Total Assets		$	19,507			$	7,431
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases		$	136			$	101
Accounts payable			346				268
Derivative instruments valuation			497				692
Deferred income taxes			—				—
Accrued expenses and other current liabilities			381				180
Current liabilities — discontinued operations			—				115
Total current liabilities			1,360				1,356
Other Liabilities
Long-term debt and capital leases			7,822				2,581
Nuclear decommissioning reserve			295				—
Nuclear decommissioning trust liability			299				—
Deferred income taxes			800				135
Derivative instruments valuation			376				137
Out-of-market contracts			2,331				298
Other non-current liabilities			407				206
Non-current liabilities — discontinued operations			—				240
Total non-current liabilities			12,330				3,597
Total Liabilities			13,690				4,953
Minority interest			1				1
3.625% Convertible Perpetual Preferred Stock (at liquidation value, net of issuance costs)			246				246
Commitments and Contingencies
Stockholders’ Equity
Preferred stock (at liquidation value, net of issuance costs)			892				406
Common Stock; $.01 par value; 500,000,000 shares authorized; 136,975,275 and 80,701,888 outstanding			1				1
Additional paid-in capital			4,448				2,431
Retained earnings			184				261
Less treasury stock, at cost — 0 and 19,346,788 shares			—				(663	)
Accumulated other comprehensive income/(loss)			45				(205	)
Total stockholders’ equity			5,570				2,231
Total Liabilities and Stockholders’ Equity		$	19,507			$	7,431

See notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

		Three Months Ended
		March 31,				March 31,
		2006				2005
		(In millions)
Cash Flows from Operating Activities
Net income		$	26			$	23
Adjustments to reconcile net income to net cash provided by operating activities
Distributions more than equity earnings of unconsolidated affiliates			(12	)			(32	)
Depreciation and amortization			125				48
Amortization of financing costs and debt discount			10				2
Write-off of deferred financing costs and debt premium			47				(8	)
Write down and loss on sale of equity method investments			3				—
Deferred income taxes			46				(6	)
Unrealized (gains)/losses on derivatives			(50	)			85
Amortization of power contracts and emission credits			9				11
Nuclear decommissioning trust liability			(3	)			—
Amortization of unearned equity compensation			3				2
Gain on sale of discontinued operations			(10	)			—
Gain on Bourbonnais legal settlement			(67	)			—
Collateral deposit payments in support of energy risk management activities			230				(136	)
Cash provided by changes in other working capital, net of acquisition and disposition affects			9				75
Net Cash Provided by Operating Activities			366				64
Cash Flows from Investing Activities
Acquisition of Texas Genco LLC, net of cash acquired			(4,263	)			—
Acquisition of WCP, net of cash acquired			(25	)			—
Proceeds from sale of discontinued operations			15				—
Proceeds from sale of investments			45				—
Proceeds from sales of nuclear decommissioning trust fund securities			45				—
Investments in nuclear decommissioning trust fund securities			(42	)			—
Decrease/(Increase) in restricted cash			(3	)			34
Decrease in notes receivable			8				68
Capital expenditures			(35	)			(11	)
Return of capital from projects			—				1
Net Cash Provided by/(Used in) Investing Activities			(4,255	)			92
Cash Flows from Financing Activities
Payment of dividends to preferred stockholders			(10	)			(4	)
Funded letter of credit			350				—
Issuance of common stock, net of issuance costs			986				—
Issuance of preferred shares, net of issuance costs			486				—
Deferred debt issuance costs			(164	)			(1	)
Proceeds from issuance of long-term debt			7,175				203
Principal payments on short and long-term debt			(4,623	)			(699	)
Net Cash Provided by/(Used in) Financing Activities			4,200				(501	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents			1				(2	)
Change in Cash from Discontinued Operations			—				(2	)
Net Increase/(Decrease) in Cash and Cash Equivalents			312				(349	)
Cash and Cash Equivalents at Beginning of Period			506				1,104
Cash and Cash Equivalents at End of Period		$	818			$	755

See notes to condensed consolidated financial statements.

NRG ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 1 — General

     NRG Energy, Inc., or “NRG”, “NRG Energy”, the “Company”, “we”, “our”, or “us”, is a wholesale power generation company, primarily engaged in the ownership and operation of power generation facilities, the transacting in and trading of fuel and transportation services, and the marketing and trading of energy, capacity and related products in the United States and internationally.

Note 2 — Summary of Significant Accounting Policies

9

     On January 1, 2006, we adopted EITF Issue No. 05-5, “Accounting for Early Retirement or Post-employment Programs with Specific Features (Such As Terms Specified in Altersteilzeit Early Retirement Arrangements)”, or EITF 05-5. EITF 05-5 provides guidance on the accounting for early retirement or post-employment programs with specific features, and specifically the terms of Altersteilzeit early retirement arrangements. The Altersteilzeit (ATZ) arrangement is a voluntary early retirement program in Germany designed to create an incentive for employees, within a certain age group, to transition from employment into retirement before their legal retirement age. If certain criteria are met by the employer, the German government provides to the employer a subsidy for bonuses paid to the employee and the additional contributions paid by the employer into the German government pension scheme under an ATZ arrangement for a maximum of six years. The Task Force reached a consensus that the employer should recognize the government subsidy when it meets the necessary criteria and is entitled to the subsidy. The Task Force also reached a consensus that payments made by the employer relative to the bonus feature and the additional contributions into the German government pension scheme (collectively, the additional compensation) should be accounted for as a post-employment benefit under SFAS 112, Employers’ Accounting for Post-employment Benefits, which prescribes that an entity should recognize the additional compensation over the period from the point at which the employee signs the ATZ contract until the end of the active service period. Upon adoption of EITF 05-5 on January 1, 2006, we recognized additional equity in earnings of unconsolidated affiliates of approximately $2.1 million, after tax, from our MIBRAG affiliate. This amount reflects the cumulative effect of the adoption of EITF 05-5, and did not materially affect our consolidated financial position, results of operations or statement of cash flows for the quarter ending March 31, 2006.

     During the period, the FASB issued SFAS No. 155 “Accounting for Certain Hybrid Financial Instruments — an amendment of FASB Statements No. 133 and 140”, or SFAS 155. This statement allows fair value measurement of certain financial instruments, and eliminates certain exemptions from fair value measurement found within SFAS 133. The fair value election would not be available for hybrid instruments with embedded derivative features that are not required to be bifurcated, such as those that are clearly and closely related to the host instrument, or hybrid instruments with an embedded derivative that is eligible for one of FAS 133’s scope exceptions. This statement is effective for all financial instruments acquired, issued, or subject to a re-measurement (new basis) event occurring after the beginning of the first fiscal year that begins after September 15, 2006. We do not expect this guidance to materially affect our consolidated financial position, results of operations or statement of cash flows.

Note 3 — Comprehensive Income/(Loss)

     The components of total comprehensive income/(loss) are:

		Three Months Ended March 31
		2006				2005
		(In millions)
Net Income		$	26			$	23
Unrealized gain/(loss) from derivative activity			247				(82	)
Foreign currency translation adjustment			3				(23	)
Other comprehensive income/(loss), net of tax			250				(105	)
Comprehensive income/(loss)		$	276			$	(82	)

     Accumulated other comprehensive income/(loss) as of March 31, 2006 is as follows:

		As of
		March 31, 2006
		(In millions)
Accumulated other comprehensive loss as of December 31, 2005		$	(205	)
Unrealized gain from derivative activity			247
Foreign currency translation adjustments			3
Accumulated other comprehensive income as of March 31, 2006			45

Note 4 — Business Combinations

Acquisition of Texas Genco LLC

     On February 2, 2006, NRG acquired Texas Genco LLC, now referred to as NRG Texas, pursuant to an Acquisition Agreement, dated September 30, 2005. As such, the results of Texas Genco LLC have been included in the consolidated financial statements since February 2, 2006. The purchase price of approximately $6.2 billion consisted of approximately $4.4 billion in cash, the issuance of approximately 35.4 million shares of NRG’s common stock valued at approximately $1.7 billion and acquisition costs of approximately $0.1 billion. This amount is subject to adjustment due to additional acquisition costs. The value of our common stock issued to the Sellers was based on our average stock price immediately before and after the closing date of February 2, 2006. The acquisition also included the assumption of approximately $2.7 billion of Texas Genco LLC debt. Texas Genco LLC is now a wholly-owned subsidiary of NRG, and is being managed and accounted for as a new business segment referred to as NRG Texas.

     The acquisition of Texas Genco LLC was partially funded at closing with the combination of (i) cash proceeds received upon the issuance and sale in a public offering of 20,855,057 shares of our common stock at a price of $48.75 per share; (ii) cash proceeds received upon the issuance and sale of $1.2 billion aggregate principal amount of 7.25% Senior Notes due 2014 and $2.4 billion aggregate principal amount of 7.375% Senior Notes due 2016; (iii) cash proceeds received upon the issuance and sale in a public offering of 2 million shares of mandatory convertible preferred stock at a price of $250 per share; (iv) funds borrowed under a new senior secured credit facility consisting of a $3.575 billion term loan facility, a $1.0 billion revolving credit facility and a $1.0 billion synthetic letter of credit facility; and (v) cash on hand.

     NRG Texas is the second-largest generation company in the ERCOT market and the largest owner of power plants in Houston. NRG Texas currently operates 48 operating generation units at nine power generation plants, including an undivided 44% interest in two nuclear generation units at STP. The aggregate net generation capacity of NRG Texas is 10,658 MW, which includes 5,178 MW of low marginal cost solid fuel and nuclear powered baseload plants. Similar to the rest of NRG, NRG Texas is a wholesale generator whose principal business is selling electric wholesale power produced by power plants to wholesale purchasers such as retail electric providers, power trading organizations and other power generation companies. To ensure steady cash flows from operations, NRG Texas has sold forward a substantial percentage of its baseload capacity under fixed price power contracts. These forward power sales agreements result primarily from bilateral negotiations.

     The acquisition of Texas Genco LLC is accounted for using the purchase method of accounting and, accordingly, the purchase price is allocated to the assets acquired and liabilities assumed based on the estimated fair value of such assets and liabilities as of February 2, 2006. As it is difficult to estimate an allocation of purchase price without completed asset appraisals, we have made a preliminary allocation. The excess of the purchase price over the fair value of the net tangible and identified intangible assets acquired is goodwill. The allocation of the purchase price may be adjusted if additional information on known contingencies existing at the date of acquisition becomes available within one year after the acquisition, and longer for certain income tax items. Changes in allocation between preliminary assessed goodwill and plant or other intangibles would result in additional non-cash amortization expense.

     The preliminary purchase price allocation is still subject to change due to additional acquisition costs. Certain asset sales, including the sale of the Webster Electric Generating Station that closed on April 7, 2006, were included as part of the working capital adjustments which were finalized on May 5, 2006.

     The following table summarizes the preliminary fair value of the assets acquired and liabilities assumed at the date of acquisition. For purposes of acquisition costs, we have estimated the acquisition costs at approximately $128 million, increasing the total purchase price to approximately $6.2 billion.

		February 2, 2006
		(In millions)
Current and non-current assets		$	1,101
Coal inventory			33
In market power contracts			60
Water contracts			72
Coal contracts			110
Nuclear fuel contracts			110
SO2 emission allowances			530
NOx emission allowances			320
Property, plant and equipment			8,154
Deferred tax asset			1,503

		February 2, 2006
		(In millions)
Goodwill — Preliminary			2,748
Total assets acquired			14,741
Current and non-current liabilities			923
Pension and post-retirement liability			213
Out of market coal contracts			140
Out of market gas swap contracts			472
Out of market power contracts			1,900
Deferred tax liability			2,127
Long term debt			2,735
Total liabilities assumed			8,510
Net assets acquired		$	6,231

     The value of goodwill is preliminary and is still subject to change as we are still in the process of valuing all assets and liabilities acquired. We are also in the process of valuing the tax basis of the assets and liabilities acquired which will affect the deferred tax balances. Any changes to the fair value assessments and tax basis values will affect the final balance of goodwill.

     The amount of goodwill as disclosed in the past has increased due to a change in several factors since the previously reported values. These factors include:

	•		Earlier estimates reported were based on estimated working capital;
	•		Changes in the forecasted projected prices of electricity, coal and emission allowances. These projections greatly affect the expected future cash flows from NRG Texas, as well as the value of intangibles and out of market contracts;
	•		The tax basis of the assets and liabilities acquired is more accurate, but still subject to revision; and
	•		More precise information in respect to identifiable intangibles.

     Currently, we have valued goodwill on a preliminary basis at approximately $2.7 billion. Our preliminary appraisal of Property, Plant and Equipment increased its fair value, as compared to Texas Genco LLC’s historical cost, by approximately $4.6 billion. If the remaining goodwill balance is indicative of a further increase in value of depreciable property plant and equipment, depreciation expense for the period ended March 31, 2006 would increase by approximately $25 million, reducing income from continuing operations before tax to a loss of approximately $7 million.

Acquisition of Remaining 50% interest in WCP

     On December 27, 2005, NRG entered into purchase and sale agreements for projects co-owned with Dynegy, Inc and these agreements were consummated on March 31, 2006. NRG acquired Dynegy’s 50% ownership interest in WCP (Generation) Holdings, Inc., or WCP, and became the sole owner of WCP’s 1,808 MW of generation in Southern California. In addition, NRG sold to Dynegy its 50% ownership interest in Rocky Road Power LLC, or Rocky Road, a 330 MW gas-fueled, simple cycle peaking plant located in Dundee, Illinois. In 2005, we wrote down the balance of our investment in Rocky Road by approximately $20 million to reflect our sale price of $45 million. NRG paid 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 unconsolidated equity method investment. The book value of NRG’s investment prior to the purchase was approximately $159 million. The acquisition of the remaining 50% interest in WCP is accounted for as a step acquisition as our original equity investment was initiated in a prior period. The purchase price of each acquisition is determined separately per the consideration given at the date of each transaction, and therefore the purchase price allocation is determined separately based on the fair value for the percentage of net assets acquired at the date of each transaction.

     Our Consolidated Balance Sheet as of March 31, 2006 assumes that the consideration paid below the historical book value of net assets acquired is related to the reduction in fair value of WCP’s fixed assets. Once the WCP asset appraisals are final, the purchase price allocation may change significantly from the amounts included herein based on the results of appraisals, changes in market prices and analyses of the income tax effects of the acquisition.

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

		(in millions)
Current assets		$	292
Property, plant and equipment			79
Intangible assets			22
Current liabilities			(26	)
Non-current liabilities			(3	)
Total Equity		$	364

Supplemental Pro Forma Information

     The following supplemental pro forma information represents the results of operations as if NRG, NRG Texas and WCP had combined at the beginning of the respective reporting periods.

		Three Months Ended March 31
		2006				2005
		(in millions)
Operating revenues		$	1,407			$	1,266
Net income/(loss)		$	(297	)		$	63
Earnings per share — Basic		$	(2.37	)		$	0.48
Earnings per share — Diluted		$	(2.37	)		$	0.48
Weighted average number of shares outstanding — Basic			130				122
Weighted average number of shares outstanding — Diluted			130				123

     The pro forma net loss for the three months ended March 31, 2006 reflect the following nonrecurring expenses incurred by Texas Genco LLC before February 2, 2006:

		(in millions)
Equity compensation costs incurred due to immediate vesting of equity compensation awards under change of control provisions		$	271
Professional fees and other acquisition-related costs			61
Total		$	332

Note 5 — Discontinued Operations

     We have classified certain 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 all of these businesses have been accounted for as discontinued operations. Accordingly, current period operating results and prior periods have been restated to report the operations as discontinued.

     Statement of Financial Accounting Standards No. 144, or SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” requires that discontinued operations be valued on an asset-by-asset basis at the lower of carrying amount or fair value less costs to sell. In applying those provisions, our management considered cash flow analyses and offers related to the assets and businesses. This amount is included in income from discontinued operations, net of income taxes in the accompanying consolidated statements of operations. In accordance with SFAS No. 144, assets held for sale will not be depreciated commencing with their classification as such.

     The assets and liabilities reported in the balance sheet as of December 31, 2005 as discontinued operations represent those of Audrain. The sale of Audrain to AmerenUE was finalized on March 29, 2006 for total cash proceeds of approximately $115 million and a net gain on sale of approximately $10 million.

     For the three months ended March 31, 2006, discontinued operations consisted of various expenses related to Audrain. For the three months ended March 31, 2005, discontinued operations consisted of various expenses related to Northbrook New York, Northbrook Energy, Audrain and NRG McClain. All of these companies are included in our Wholesale Power Generation — Other North America Segment.

     Summarized results of operations of discontinued operations were as follows:

		Three Months Ended
		March 31,				March 31,
		2006				2005
		(In millions)
Operating revenues		$	(1	)		$	4
Pretax gain/(loss) from operations of discontinued components			(2	)			1
Gain from sale of discontinued operations, net of income taxes			10				—

Note 6 — Investments Accounted for by the Equity Method

     We have a 50% interest in MIBRAG and WCP, which were considered significant, as defined by applicable SEC regulations. As described in Note 4 above, we acquired the remaining 50% interest in WCP on March 31, 2006.

MIBRAG Summarized Financial Information

     For the three months ended March 31, 2006 and 2005, we recorded equity earnings for MIBRAG of $12 million and $7 million, respectively. The following table summarizes the results of operations for MIBRAG, including interests owned by the Company and other parties for the periods shown below:

Results of Operations

		Three Months Ended
		March 31
		2006				2005
		(In millions)
Operating revenues		$	109			$	112
Operating income			30				22
Net income			24				16

     As described in Note 2, we adopted EITF 04-6 as of January 1, 2006, which has negatively affected our equity investment in MIBRAG. As of December 31, 2005, MIBRAG had an asset totaling €157 million, approximately $185 million, representing the stripping costs incurred during mining operations, net of depreciation. Per the guidance of EITF 04-6, upon its adoption, the value of such stripping cost is to be eliminated with an offsetting charge to retained earnings. As such, our investment in MIBRAG has been reduced by 50% of the above mentioned asset, or approximately $93 million after tax, with an offsetting charge to retained earnings.

WCP Summarized Financial Information

     For the three months ended March 31, 2006, we recorded equity earnings of $1 million for WCP after adjustments for the reversal of $2 million of project level depreciation expense. For the three months ended March 31, 2005, we recorded equity earnings of $4 million for WCP after adjustments for the reversal of $3 million of project level depreciation expense. The following table summarizes financial information for WCP, including interests owned by us and other parties for the periods shown below:

Summarized Results of Operations

		Three Months Ended
		March 31
		2006				2005
		(In millions)
Operating revenues		$	67			$	86
Operating income			(4	)			—
Net income (pretax)			(2	)			2

     NRG Cadillac

     On January 1, 2006, NRG sold a 49.5% interest in a 38 MW biomass fuels generation facility located in Cadillac, Michigan, along with its right to receive Production Tax Credits, or PTCs, through 2009 to Lakes Renewable LLC. In consideration, NRG received an up-front payment of $0.3 million, approximately $4 million in a note receivable and a promissory note equal to the value of its share in future PTCs earned through 2009. The sale was contingent on the receipt of a favorable private letter ruling from the IRS and accordingly, all consideration was to be held in escrow. On April 13, 2006, NRG sold its remaining 0.5% share in Cadillac along with its interest in the notes receivable and promissory note to Delta Power for approximately $11 million. We will record a gain on the sale of approximately $10 million in the second quarter of 2006.

     James River

     NRG expects to sign a purchase and sale agreement to sell its 50% interest in James River in the second quarter 2006. As a result of this transaction, NRG wrote down the value of its equity investment by approximately $3 million in March 2006. We expect to close on the sale in the second quarter 2006.

Note 7 — Accounting for Derivative Instruments and Hedging Activities

     FAS 133 “Accounting for Derivative Instruments and Hedging Activities”, or FAS 133, as amended, requires us to recognize all derivative instruments on the balance sheet as either assets or liabilities and measure them at fair value each reporting period. If certain conditions are met, we may be able to designate our derivatives as cash flow hedges and defer the effective portion of the change in fair value of the derivatives in Accumulated Other Comprehensive Income, or OCI and subsequently recognize in earnings when the hedged items impact income. The ineffective portion of a cash flow hedge is immediately recognized in income.

     For derivatives designated as hedges of the fair value of assets or liabilities, the changes in fair value of both the derivatives and the hedged items are recorded in current earnings. The ineffective portion of a hedging derivative instrument’s change in fair values is immediately recognized in earnings.

     For derivatives that are not designated as cash flow hedges and do not qualify for hedge accounting treatment, the changes in the fair value will be immediately recognized in earnings. Under the guidelines established by FAS 133, as amended, certain derivative instruments may qualify for the normal purchase and sale exception and are therefore exempt from fair value accounting treatment. FAS 133 applies to our energy related commodity contracts, interest rate swaps and foreign exchange contracts.

     As the Company engages principally in the trading and marketing of its generation assets, most of our commercial activities qualify for hedge accounting under the requirements of FAS 133. In order to so qualify, the physical generation and sale of electricity must be highly probable at inception of the trade and throughout the period it is held, as is the case with our base-load coal plants. For this reason, trades in support of the company’s peaking units will not generally qualify for hedge accounting treatment and any changes in fair value are likely to be reflected on a mark-to-market basis in the statement of operations. The majority of trades in support of our base-load coal units will normally qualify for hedge accounting treatment and any fair value movements will be reflected in the balance sheet as part of OCI.

     FAS 133 applies to our energy related commodity contracts, interest rate swaps and foreign exchange contracts.

Accumulated Other Comprehensive Income (OCI)

     The following table summarizes the effects of FAS 133 on our OCI balance attributable to hedged derivatives for the three months ended March 31, 2006 before income taxes:

		Energy				Interest
		Commodities				Rate				Total
		(In millions)
Accumulated OCI balance at December 31, 2005		$	(204	)		$	8			$	(196	)
Unwound from OCI during the period:
— Due to unwinding of previously deferred amounts			(9	)			(2	)			(11	)
Mark to market of hedge contracts (net of tax)			216				42				258
Accumulated OCI balance at March 31, 2006		$	3			$	48			$	51
Gains/(Losses) expect to unwind from OCI during the next 12 months			(37	)			2				(35	)

     The following table summarizes the effects of FAS 133 on our OCI balance attributable to hedged derivatives for the three months ended March 31, 2005:

		Energy				Interest
		Commodities				Rate				Total
		(In millions)
Accumulated OCI balance at December 31, 2004		$	5			$	2			$	7
Unwound from OCI during the period:
— Due to unwinding of previously deferred amounts			(3	)			1				(2	)
Mark to market of hedge contracts (net of tax)			(90	)			10				(80	)
Accumulated OCI balance at March 31, 2005		$	(88	)		$	13			$	(75	)
Gains/(Losses) expected to unwind from OCI during the next twelve months			(76	)			6				(70	)

     Gains of $11 million and gains of $2 million were reclassified from OCI to current period earnings during the three months ended March 31, 2006 and 2005, respectively, due to the unwinding of previously deferred amounts. These amounts are recorded on the

same line in the statement of operations in which the of hedged items are recorded. Also during the three months ended March 31, 2006 and 2005, we recorded gains in OCI of $258 million and losses of $80 million, respectively, related to changes in the fair values of derivatives accounted for as hedges. The net balance in OCI relating to FAS 133 as of March 31, 2006 was an unrecognized gain of approximately $51 million. We expect $35 million of deferred net losses on derivative instruments accumulated in OCI to be recognized in earnings during the next twelve months.

Statement of Operations

     The following table summarizes the pre-tax effects of non-hedge derivatives and derivatives that no longer qualify as hedges on our statement of operations for the three months ended March 31, 2006:

		Energy				Interest
		Commodities				Rate				Total
		(In millions)
Revenue from majority-owned subsidiaries		$	49			$	—			$	49
Equity in net earnings of unconsolidated affiliates			—				—				—
Interest expense			—				(3	)			(3	)
Total statement of operations impact before tax		$	49			$	(3	)		$	46

     The following table summarizes the pre-tax effects of non-hedge derivatives and derivatives that no longer qualify as hedges on our statement of operations for the three months ended March 31, 2005:

		Energy				Interest
		Commodities				Rate				Total
		(In millions)
Revenue from majority-owned subsidiaries		$	(87	)		$	—			$	(87	)
Equity in net earnings of unconsolidated affiliates			12				—				12
Cost of operations			4				—				4
Total statement of operations impact before tax		$	(71	)		$	—			$	(71	)

Energy Related Commodities

     As part of our risk management activities, we manage the commodity price risk associated with our competitive supply activities and the price risk associated with power sales from our electric generation facilities. In doing so, we may enter into a variety of derivative and non-derivative instruments, including the following:

	•		Forward contracts, which commit us to purchase or sell energy commodities in the future;
	•		Futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial instrument;
	•		Swap agreements, which require payments to or from counter-parties based upon the differential between two prices for a predetermined contractual (notional) quantity; and
	•		Option contracts, which convey the right to buy or sell a commodity, financial instrument, or index at a predetermined price.

     The objectives for entering into such hedges include:

	•		Fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return on our electric generation operations;
	•		Fixing the price of a portion of anticipated fuel purchases for the operation of our power plants; and
	•		Fixing the price of a portion of anticipated energy purchases to supply our load-serving customers.

     During the three months ended March 31, 2006, we recognized losses of $8 million associated with the ineffectiveness on commodity cash flow hedges in support of our power generation activities. During the three months ended March 31, 2005, ineffectiveness on our commodity cash flow hedge relationships was immaterial to our financial results.

     During the three months ended March 31, 2006 and 2005, our pre-tax earnings were affected by an unrealized gain of $49 million and an unrealized loss of $83 million, respectively, associated with changes in the fair value of energy related derivative instruments not accounted for as hedges in accordance with FAS 133. These amounts exclude the effect of unrealized gains and losses recorded by equity investees.

     During the three months ended March 31, 2006 and 2005, we reclassified gains of $9 million and gains of $3 million, respectively, from OCI to current period earnings. Also during the three months ended March 31, 2006 and 2005, we recorded gains in OCI of $216 million and losses of $90 million, respectively, related to changes in the fair value of derivatives accounted for as hedges. We expect to reclassify approximately $37 million of deferred losses to earnings during the next twelve months on energy related derivative instruments accounted for as hedges. At March 31, 2006, we had hedge and non-hedge energy related commodities financial instruments extending through December 2026.

Interest Rates

     We are exposed to changes in interest rates through our issuance of variable rate and fixed rate debt. In order to manage this interest rate risk, we have entered into interest-rate swap agreements. In January 2006, in anticipation of the New Senior Credit Facility, we entered into a series of forward starting interest rate swaps intended to hedge the variability in cash flows associated with this debt issuance. These transactions were designated as cash flow hedges and any gains/(losses) will be deferred on the balance sheet in Other Comprehensive Income. In February 2006, with the completion of the sale of the Senior Notes, we designated our fixed-to-floating interest rate swap as a hedge of fair value changes in the Senior Notes. This interest rate swap was previously designated as a hedge of our Second Priority Notes which were effectively replaced by the Senior Notes. In the first quarter, we recognized approximately $3 million in ineffectiveness associated with this hedging relationship.

     At March 31, 2006, all of our interest rate swap arrangements have been designated as either cash flow or fair value hedges.

     During the three months ended March 31, 2006 and 2005, our pre-tax earnings were not impacted by changes in the fair value of interest rate derivative instruments not accounted for as hedges in accordance with SFAS No. 133. During the three months ended March 31, 2006 and 2005, we reclassified gains of $2 million and losses of $1 million, respectively, from OCI to current period earnings and expect to reclassify approximately $2 million of deferred gains to earnings during the next twelve months associated with interest rate swaps accounted for as hedges.

     At March 31, 2005, we had various interest-rate swap agreements extending through June 2019.

Foreign Currency Exchange Rates

     To preserve the U.S. dollar value of projected foreign currency cash flows, we may hedge, or protect those cash flows if appropriate foreign hedging instruments are available. As of March 31, 2006, the results of any outstanding foreign currency exchange contracts were immaterial to our financial results.

Note 8 —Long-term Debt and Capital Leases

Cash Tender Offer and Consent Solicitation

     On December 15, 2005, we commenced a cash tender offer and consent solicitation for any and all outstanding $1.1 billion aggregate principal amount of our 8% Second Priority Notes, or the NRG Notes. On such date, we also commenced a cash tender offer and consent solicitation for any and all outstanding $1.1 billion aggregate principal amount of Texas Genco and Texas Genco Financing Corp.’s 6.875% senior notes due 2014, or the Texas Genco Notes. The offer to purchase the NRG Notes and the Texas Genco Notes was part of our previously announced financing plan in connection with our acquisition of Texas Genco LLC. As of February 2, 2006, NRG had received valid tenders from holders in aggregate principal amount of the NRG Notes, representing approximately 99.96% of the outstanding NRG Notes, and had received valid tenders from holders of the $1.1 billion in aggregate principal amount of the Texas Genco Notes, representing 100% of the outstanding Texas Genco Notes. The purchase price for the Second Priority Notes totaling approximately $1.2 billion was paid by NRG on February 2, 2006 and included $0.1 billion prepayment penalty which was recorded within debt refinancing expense on the consolidated income statement. The purchase price for the Texas Genco Notes totaling approximately $1.2 billion was paid by NRG on February 3, 2006 and include $0.1 billion prepayment penalty which was recorded as an acquisition cost for the acquisition of NRG Texas (see Note 4).

     On January 31, 2006, we used proceeds from the issuance of common stock and cash on hand to repay the $446 million outstanding principal balance of our senior secured term loan facility, along with accrued but unpaid interest of approximately $2 million and terminated the facility. On February 2, 2006, we used proceeds from the new debt financing to pay accrued but unpaid fees on our revolving credit facility and our funded letter of credit, and terminated those facilities which were replaced by a new term loan, letter of credit and revolving finance facilities as of February 2, 2006.

New Financings

New Senior Credit Facility

     On February 2, 2006, we also entered into a new senior secured credit facility with a syndicate of financial institutions, including Morgan Stanley Senior Funding, Inc., as administrative agent, Morgan Stanley & Co., Inc., as collateral agent, and Morgan Stanley Senior Funding, Inc. and Citigroup Global Markets Inc. as joint lead book-runners, joint lead arrangers and co-documentation agents providing for up to an aggregate amount of $5.575 billion, or the New Senior Credit Facility. The New Senior Credit Facility consists

of a $3.575 billion senior first priority secured term loan facility, or the Term Loan Facility, a $1.0 billion senior first priority secured revolving credit facility, or the Revolving Credit Facility, and a $1.0 billion senior first priority secured synthetic letter of credit facility, or the Letter of Credit Facility. The New Senior Credit Facility replaced our then existing senior secured credit facility. The Term Loan Facility will mature on February 1, 2013 and will amortize in 27 consecutive equal quarterly installments of 0.25% of the original principal amount of the Term Loan Facility, beginning June 30, 2006, with the balance payable on the seventh anniversary thereof. The full amount of the Revolving Credit Facility will mature on February 2, 2011. The Letter of Credit Facility will mature on February 1, 2013 and no amortization will be required in respect thereof. As of March 31, 2006, we had $3.575 billion outstanding under our Term Loan Facility. As of March 31, 2006, we had issued $798 million under our Letter of Credit Facility and $154 million in letters of credit under our Revolving Credit Facility.

     The New Senior Credit Facility is guaranteed by substantially all of our existing and future direct and indirect subsidiaries, with certain customary or agreed-upon exceptions for unrestricted foreign subsidiaries, project subsidiaries and certain other subsidiaries. The capital stock of substantially all of our subsidiaries, with certain exceptions for unrestricted subsidiaries, foreign subsidiaries and project subsidiaries has been pledged for the benefit of the New Senior Credit Facility lenders.

     The New Senior Credit Facility is also secured by first-priority perfected security interests in substantially all of the property and assets owned or acquired by us and our subsidiaries, other than certain limited exceptions. These exceptions include assets such as the assets of certain unrestricted subsidiaries, equity interests in certain of our project affiliates that have non-recourse debt financing, and voting equity interests in excess of 66% of the total outstanding voting equity interest of certain of our foreign subsidiaries.

     The New Senior Credit Facility contains customary covenants, which among other things require us to meet certain financial tests, including a minimum interest coverage ratio and a maximum leverage ratio on a consolidated basis, and limit our ability to:

	•		incur indebtedness and liens and enter into sale and lease-back transactions;
	•		make investments, loans and advances;
	•		engage in mergers, acquisitions, consolidations and asset sales;
	•		pay dividends and other restricted payments;
	•		enter into transactions with affiliates;
	•		engage in business activities and hedging transactions;
	•		make capital expenditures;
	•		make debt payments; and
	•		make certain changes to the terms of material indebtedness.

     In anticipation of the New Senior Credit Facility, in January 2006, we entered into a series of 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, we pay our counterparty the equivalent of a fixed interest payment on a predetermined notional value, and we receive quarterly the equivalent of a floating interest payment based on 3-month LIBOR calculated on the same notional value. All payments by us and our counterparties are made quarterly, and 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 is $2.15 billion. The notional amounts and maturities of each tranche of these swaps are as follows:

Period of swap		Notional Value				Maturity
1-year		$120 million				March 31, 2007
2-year		$140 million				March 31, 2008
3-year		$150 million				March 31, 2009
4-year		$190 million				March 31, 2010
5-year		$1.55 billion				March 31, 2011

Senior Notes

     On February 2, 2006, we completed the sale of (i) $1.2 billion aggregate principal amount of 7.25% senior notes due 2014, or 7.25% Senior Notes, and (ii) $2.4 billion aggregate principal amount of 7.375% senior notes due 2016, or 7.375% Senior Notes, collectively the Senior Notes. The Senior Notes were issued under an Indenture, dated February 2, 2006, or the Indenture, between us and Law Debenture Trust Company of New York, as trustee, or the Trustee, as supplemented by a First Supplemental Indenture, dated February 2, 2006, between us, the Guarantors named therein and the Trustee, relating to the 7.25% Senior Notes, and as supplemented by a Second Supplemental Indenture, dated February 2, 2006, between us, the Guarantors named therein and the Trustee, relating to the 7.375% Senior Notes. On March 14, 2006, we executed a Third Supplemental Indenture and a Fourth Supplemental Indenture,

whereby the recently acquired NRG Texas subsidiaries were added as Guarantors. On April 28, 2006, we executed a Fifth Supplemental Indenture and a Sixth Supplemental Indenture, whereby the West Coast subsidiaries were added as Guarantors. The Indentures and the form of notes provide, among other things, that the Senior Notes will be senior unsecured obligations of NRG.

     Interest is payable on the Senior Notes on February 1 and August 1 of each year beginning on August 1, 2006 until their maturity dates — February 1, 2014 for the 7.25% Senior Notes and February 1, 2016 for the 7.375% Senior Notes. As of March 31, 2006, we had $3.6 billion in principal outstanding under our Senior Notes.

     At any time prior to February 1, 2009, we may redeem up to 35% of the aggregate principal amount of the series of Senior Notes with the net proceeds of certain equity offerings, at a redemption price of 107.25% of the principal amount, in the case of the 7.25% Senior Notes, and 107.375% of the principal amount, in the case of the 7.375% Senior Notes. In addition, we may redeem the 7.25% Notes and 7.375% Notes at the redemption prices expressed as a percentage of the principal amount redeemed set forth below, plus accrued and unpaid interest on the notes redeemed.

     Prior to February 1, 2010 for the 7.25% Notes (the “First Applicable 7.25% Redemption Date”), we may redeem all or a portion of the 7.25% Notes at a price equal to 100% of the principal amount plus a premium and accrued interest. The premium is the greater of i) 1% of the principal amount of the note, or ii) the excess of the principal amount of the note over the following: the present value of 103.625% of the note, plus interest payments due on the Note from the date of redemption through the First Applicable 7.25% Redemption Date, discounted at a Treasury rate plus 0.50%. The following table sets forth the premium upon redemption for the 7.25% notes.

			Premium as defined above
Prior to February 1, 2010
February 1, 2010 to February 1, 2011			103.625	%
February 1, 2011 to February 1, 2012			101.813	%
February 1, 2012 and thereafter			100.000	%

     Prior to February 1, 2011 for the 7.375% Notes (the “First Applicable 7.375% Redemption Date”), we may redeem all or a portion of the 7.375% Notes at a price equal to 100% of the principal amount plus a premium and accrued interest. The premium is the greater of i) 1% of the principal amount of the note, or ii) the excess of the principal amount of the note over the following: the present value of 103.688% of the note, plus interest payments due on the Note from the date of redemption through the First Applicable 7.375% Redemption Date, discounted at a Treasury rate plus 0.50%. The following table sets forth the premium upon redemption for the 7.375% notes.

			Premium as defined above
Prior to February 1, 2011
February 1, 2011 to February 1, 2012			103.688	%
February 1, 2012 to February 1, 2013			102.458	%
February 1, 2013 to February 1, 2014			101.229	%
February 1, 2014 and thereafter			100.000	%

     The Indentures provide for customary events of default which include, among others, nonpayment of principal or interest; breach of other agreements in the Indentures; defaults in failure to pay certain other indebtedness; the rendering of judgments to pay certain amounts of money against us and our subsidiaries; the failure of certain guarantees to be enforceable; and certain events of bankruptcy or insolvency. Generally, if an event of default occurs, the Trustee or the Holders of at least 25% in principal amount of the then outstanding series of Senior Notes may declare all of the Senior Notes of such series to be due and payable immediately.

     The terms of the Indentures, among other things, limit our ability and certain of our subsidiaries’ ability to:

	•		make restricted payments;
	•		restrict dividends or other payments of subsidiaries;
	•		incur additional debt;
	•		engage in transactions with affiliates;
	•		create liens on assets;
	•		engage in sale and leaseback transactions; and
	•		consolidate, merge or transfer all or substantially all of our assets and the assets of our subsidiaries.

Project Financing

     On March 29, 2006, we completed the sale of the Audrain Generating Station to AmerenUE, a subsidiary of Ameren Corporation. Included in the purchase was Ameren’s assumption of $240 million of non-recourse capital lease obligations and assignment of a $240 million note receivable.

Note 9 — Changes in Capital Structure

     As of March 31, 2006, we had 10,000,000 authorized preferred shares, 2,670,000 of which have been issued and are outstanding. The outstanding preferred shares are comprised of: 420,000 of 4% Preferred Stock, 250,000 of 3.625% Preferred Stock and 2,000,000 5.75% Preferred Stock.

5.75% Preferred Stock

     On February 2, 2006, we completed the issuance of 2 million shares of 5.75% mandatory convertible preferred stock, or the 5.75% Preferred Stock, at an offering price of $250 per share for total net proceeds after deducting offering expenses and underwriting discounts of approximately $486 million. Dividends on the 5.75% Preferred Stock are $14.375 per share per year, and are due and payable on a quarterly basis beginning on March 15, 2006. The 5.75% Preferred Stock will automatically convert into common stock on March 16, 2009, or the Conversion Date, at a rate that is dependent upon the applicable market value of our common stock. If the applicable market value of our common stock is $60.45 a share or higher at the Conversion Date, then the 5.75% Preferred Stock is convertible at a rate of 4.1356 shares of our common stock for every share of 5.75% Preferred Stock outstanding. If the applicable market value of our common stock is less than or equal to $48.75 per share at the Conversion Date, then the 5.75% Preferred Stock is convertible at a rate of 5.1282 shares of our common stock for every share of 5.75% Preferred Stock outstanding. If the applicable market value of our common stock is between $48.75 per share and $60.45 per share at the Conversion Date, then the 5.75% Preferred Stock is convertible into common stock at a rate that is prorated between 4.1356 and 5.1282 shares of common stock for every share of 5.75% Preferred Stock.

Common Stock issued to the public

     On January 31, 2006, we completed the issuance of 20,855,057 shares of our common stock, or the Common Stock, at an offering price of $48.75 per share for total net proceeds after deducting offering expenses and underwriting discounts of approximately $986 million.

Stock issued to the Sellers pursuant to the Acquisition Agreement

     On February 2, 2006, pursuant to the Acquisition Agreement, we issued 35,406,292 shares to the Sellers. Of this amount, 19,346,788 shares were issued from treasury and 16,059,504 were newly issued shares. Also see Note 4.

Second Lien Structure

     Before the Acquisition, Texas Genco LLC’s capital structure permitted the grant of second priority liens on its assets as security for their obligations under certain long-term power sales agreements and related hedges. The Credit Agreement for the New Senior Credit Facility and the Indentures, which became effective as of February 2, 2006, allow these arrangements to remain in place. In addition, the new debt instruments also permit us to grant second priority liens on our other assets in the United States in order to secure obligations under power sales agreements and related hedges, within certain limits. 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 long term power sales and related hedges.

     As of April 24, 2006, our net mark-to-market exposure on the hedges that are subject to the second lien structure was $2.1 billion. The following table summarizes the utilization of the second lien structure as of March 31, 2006:

		12 Months Starting
		April 1,				April 1,				April 1,				April 1,				April 1,
		2006				2007				2008				2009				2010
Equivalent Net Sales secured by Second Lien Structure(1)
In MW			1,610				3,067				2,522				3,028				1,688
As a percentage of net baseload capacity in collateral pool as of February 2, 2006			30	%			44	%			36	%			43	%			22	%

Note 10 — Equity Compensation

     Incentive Compensation Plans

     In December 2004, the FASB issued a revision to SFAS 123, or SFAS 123(R) “Share-Based Payment” which requires us to modify our recognition of expense for stock based compensation in the statement of income. We have adopted the requirements of SFAS 123(R) effective January 1, 2006 using the modified prospective approach. The provisions of SFAS 123(R) did not result in a significant change in our compensation expense because we previously recognized compensation expense in our statements of income under SFAS 123. In accordance with SFAS 123(R), we have estimated a forfeiture rate for each of our awards based on the number of instruments expected to vest rather than recording the actual forfeitures as they occur. The elimination of unearned compensation and amounts previously recognized in income related to the application of the new forfeiture rate to outstanding instruments as of January 1, 2006 was immaterial to our results.

     Long-Term Incentive Plan, or LTIP

     As of March 31, 2006, a total of 4,000,000 shares of our common stock are available for issuance under the LTIP, subject to adjustment in the event of a reorganization, recapitalization, stock split, reverse stock split, stock dividend, and combination of shares, merger or similar change in our structure or our outstanding shares of common stock. NRG’s policy for issuing common stock shares upon LTIP award exercise is to issue treasury shares. If there are no treasury shares available, new shares of common stock will be issued. There were 248,465 and 1,355,193 shares of common stock remaining available for grants under our LTIP as of March 31, 2006 and December 31, 2005, respectively.

     On April 28, 2006, NRG’s shareholders approved an amendment to increase the number of shares available under the LTIP from 4,000,000 to 8,000,000 shares.

     Stock Options, or NQSO’s

     NQSO’s granted under the Long-Term Incentive Plan have a three-year graded vesting schedule beginning on the grant date and become exercisable at the end of this requisite service period. As provided for by SFAS 123(R) for share options with graded vesting issued after January 1, 2006, we recognize compensation cost on a straight-line basis over the requisite service period for the entire award. The maximum contractual term is ten years for approximately 600,000 of our outstanding NQSO shares, and six years for the other 1.1 million outstanding. The aggregate intrinsic value for stock options outstanding at March 31, 2006 and March 31, 2005 is approximately $20 million and $11 million, respectively. The aggregate intrinsic value for stock options exercisable at March 31, 2006 and March 31, 2005 is approximately $13 million and $3 million, respectively. The weighted average contractual term for stock options outstanding at March 31, 2006 and March 31, 2005 is 6.1 and 7.4 years respectively. The weighted average contractual term for stock options exercisable at March 31, 2006 and March 31, 2005 is 6.6 and 7.7 years respectively.

     The fair value of the stock option grants were estimated on the date of grant using the Black-Scholes option-pricing model. The following table summarizes the assumptions used to measure fair value and shows the change in the outstanding NQSO balance for the three months ended March 31, 2006 and March 31, 2005:

						Weighted				Weighted Average
						Average				Grant-Date Fair
		Shares				Exercise Price				Value Per Share
Outstanding as of December 31, 2004			962,751			$	23.15			$	12.15
Granted			—				—
Canceled or Expired			—				—
Exercised			—				—
Outstanding at March 31, 2005			962,751				23.15				12.15
Exercisable at March 31, 2005			288,249				23.14				12.27
Outstanding as of December 31, 2005			1,095,251				25.04
Granted			671,421				47.39				15.90
Canceled or Expired			(47,800	)			35.19
Exercised			(9,000	)			19.90				9.45
Outstanding at March 31, 2006			1,709,872				33.56
Exercisable at March 31, 2006			591,164				23.24				12.29

     The fair value of NQSO’s issued during the three months ended March 31, 2006 were based on the following assumptions:

		Three Months Ended
		March 31, 2006
Expected Volatility			28.10% -28.42	%
Weighted Average Volatility			28.31	%
Expected Dividends			—
Expected Term (in years)			4
Risk Free Rate			4.30%-4.66	%
Forfeiture Rate			8	%

     We use an expected term of four years for NQSO’s based on the simple average of the contractural term and vesting term. Volatility is calculated based on a blended average of NRG and NRG’s industry peers’ historical 2-year stock price volatility data. A forfeiture rate of 8% was calculated for NQSO’s based on an analysis of NRG’s historical forfeitures, employment turnover, and expected future behavior.

     Restricted Stock Units, or RSU’s

RSU’s granted under the Long-Term Incentive Plan fully vest three years from the date of issuance. To calculate compensation expense, the fair value of the RSU is based on the closing price of our common stock on the date of grant. Such compensation expense, net of forfeitures, is amortized over the three-year requisite service period. We determined two separate forfeiture rates that best represent the employment termination behavior related to issued RSU’s, 8% for senior management and 25% for all other employees. The forfeiture rates were based on an analysis of our historical forfeitures, employment turnover, and expected future behavior. The aggregate intrinsic value for non-vested RSU’s on March 31, 2006 and March 31, 2005 is $65.3 and $30.1 million respectively.

     The following table shows the change in the outstanding RSU balance for the three months ended March 31, 2005 and 2006:

						Weighted
						Average Grant-
						Date Fair Value
Non-vested Shares		Shares				Per Share
Non-vested as of December 31, 2004			880,994			$	21.59
Granted			12,250				35.23
Vested			—				—
Canceled			(11,500	)			21.84
Non-vested at March 31, 2005			881,744				20.84
Non-vested as of December 31, 2005			1,285,944				27.14
Granted			195,839				47.18
Vested			—				—
Canceled			(39,650	)			28.95
Non-vested at March 31, 2006			1,442,133				29.83

     Deferred Stock Units, or DSU’s

     DSU’s granted under the LTIP are fully vested at the date of issuance. Compensation expense recorded is the fair value of the DSU based on the closing price of our common stock on the date of grant. For DSU’s, compensation expense is fully recognized in the period of grant. The aggregate intrinsic value for DSU’s outstanding at March 31, 2006 and March 31, 2005 is approximately $6 and $4 million respectively. The aggregate intrinsic value for DSU’s converted for the three months ended March 31, 2006 and March 31, 2005 is $0.2 million and $0.1 million respectively.

     The following table shows the change in the outstanding DSU balance for the three months ended March 31, 2005 and 2006:

						Weighted Average
						Grant-Date Fair
		Shares				Value Per Share
Outstanding as of December 31, 2004			60,281			$	20.31
Granted			50,110				37.85
Conversions			(4,174	)			33.12
Canceled or Expired			—				—
Outstanding at March 31, 2005			106,217				28.08
Outstanding as of December 31, 2005			122,184				29.21
Granted			4,054				43.43
Conversions			(3,548	)			29.31
Canceled or Expired			—				—
Outstanding at March 31, 2006			122,690				29.68

     Performance Units, or PU’s

     40,900 of our outstanding PU’s will be paid out on August 1, 2008 if the Measurement Price, that is the average closing price of our common stock for the ten trading days prior to August 1, 2008, is equal to or greater than the Target Price of $54.50. The payout for each performance unit will be equal to: (i) one share of common stock, if the Measurement Price equals the Target Price; (ii) a pro-rated amount between one and two shares of common stock, if the Measurement Price is greater than the Target Price but less than the Maximum Price of $63.75; and (iii) two shares of common stock, if the Measurement Price is equal to or greater than the Maximum Price. The other 165,432 outstanding PU’s will be paid out in the first quarter of fiscal year 2009 if the Measurement Price is equal to or greater than the following Target Prices:

Grant Date		Shares				Target Price				Maximum Price
1/3/06			92,300			$	67.37			$	78.78
2/3/06			52,632			$	66.41			$	77.67
3/1/06			25,000			$	61.82			$	72.29

     The fair value of the PU’s was estimated on the date of grant using a Monte Carlo stimulation model. Volatility is calculated based on a blended average of NRG and NRG’s industry peers’ 2-year historical stock price volatility data. Compensation expense, net of a 8% forfeiture rate, will be amortized over the three-year requisite service period. The following table shows the change in the outstanding PU balance for the three months ended March 31, 2006 (no PU’s were issued during the three months ended March 31, 2005) and summarizes the assumptions and weighted average assumptions used in the fair value model:

						Weighted Average
						Grant-Date Fair
Non-vested Shares		Shares				Value Per Share
Non-vested as of December 31, 2005			44,900			$	29.87
Granted			169,932				34.62
Vested			—				—
Canceled			(8,500	)			32.45
Non-vested at March 31, 2006			206,332				33.68

     The aggregate intrinsic value for PU’s outstanding March 31, 2006 is approximately $9 million. There were no PU’s outstanding as of March 31, 2005. Significant assumptions used during the period – PU’s:

		Three Months Ended
		3/31/2006
Expected Volatility			28.10% -28.42	%
Weighted Average Volatility			28.32	%
Expected Dividends			—
Expected Term (in years)			3
Risk Free Rate			4.30%-4.68	%
Forfeiture Rate			8	%

Supplemental information:

     For the three months ended March 31, 2006 and March 31, 2005 we did not capitalize any equity compensation costs. In addition, we did not recognize a deferred tax asset related to equity compensation because we are under a full valuation allowance for both periods. Cash received for the exercise of all awards was $0.2 million and $0 for the three months ended March 31, 2006 and March 31, 2005 respectively.

     The following table summarizes total compensation expense recognized in accordance with FAS 123(R) for the three months ended March 31, 2006 and March 31, 2005 for each of the four types of awards issued under NRG’s Long-Term Incentive Plan. Total non-vested compensation cost not yet recognized is also presented as of March 31, 2006:

										Total non-vested
										Compensation Cost				Weighted average
		Compensation Expense								Not Yet Recognized				life remaining
		Three months ending March 31								As of				As of
Award		2006				2005				March 31, 2006				March 31, 2006
		(in millions)
Stock Options			0.7				0.9				11.7				1.6
Deferred Stock Units			0.2				—				—				—
Restricted Stock Units			1.5				1.2				26.8				1.6
Performance Units			0.5				—				6.3				2.7
Total		$	2.9			$	2.1			$	44.8

Note 11 — Earnings Per Share

     Basic earnings per common share were computed by dividing net income less accumulated preferred stock dividends by the weighted average number of common stock shares outstanding. Shares issued 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.

     Dilutive effect for equity compensation — The outstanding non-qualified stock options, non-vested restricted stock units, deferred stock units and performance units are not considered outstanding for purposes of computing basic earnings per share. However, these instruments are included in the denominator for purposes of computing diluted earnings per share under the treasury stock method or the if-converted method. The dilutive effect of the potential exercise of outstanding non-qualified stock options, non-vested restricted stock units and performance units is calculated using the treasury stock method. The dilutive effect of the deferred stock units is included in the denominator for purposes of computing diluted earnings per share under the if-converted method.

     Dilutive effect for other equity instruments — The outstanding 4% Preferred Stock, 3.625% Preferred Stock and 5.75% Preferred Stock are not considered outstanding for purposes of computing basic earnings per share. However, these instruments are considered for inclusion in the denominator for purposes of computing diluted earnings per share under the if-converted method.

     The reconciliation of basic earnings per common share to diluted earnings per share is shown in the following table:

		Three Months Ended March 31
		2006				2005
		(In millions, except per share data)
Basic earnings per share
Numerator:
Income from continuing operations		$	18			$	22
Preferred stock dividends			(11	)			(4	)
Net income available to common stockholders from continuing operations			7				18
Discontinued operations, net of tax			8				1
Net income available to common stockholders		$	15			$	19

		Three Months Ended March 31
		2006				2005
		(In millions, except per share data)
Denominator:
Weighted average number of common shares outstanding			117.4				87
Basic earnings per share:
Income from continuing operations		$	0.06			$	0.20
Discontinued operations, net of tax			0.07				0.01
Net income		$	0.13			$	0.21
Diluted earnings per share
Numerator:
Net income available to common stockholders from continuing operations		$	7			$	18
Add preferred stock dividends for dilutive preferred stock			—				—
Adjusted income from continuing operations			7				18
Discontinued operations, net of tax			8				1
Net income available to common stockholders		$	15			$	19
Denominator:
Weighted average number of common shares outstanding			117.4				87
Incremental shares attributable to the issuance of non-vested restricted stock units (treasury stock method)			0.8				0.4
Incremental shares attributable to the assumed conversion of deferred stock units (if-converted method)			0.1				0.1
Incremental shares attributable to the issuance of non-vested non-qualifying stock options (treasury stock method)			0.5				0.2
Total dilutive shares			118.8				87.7
Diluted earnings per share:
Income from continuing operations		$	0.06			$	0.20
Discontinued operations, net of tax			0.07				0.01
Net income		$	0.13			$	0.21

     For the three months ended March 31, 2006 and March 31, 2005, options to purchase 595,121 and 727,751 shares of common stock, respectively, were not included in the computation because the effect would be anti-dilutive.

     For the three months ended March 31, 2006 and March 31, 2005, outstanding preferred shares which are convertible into 18,771,200 and 10,500,000 shares of common stock, respectively, were not included in the computation because the effect would be anti-dilutive.

Note 12 — Segment Reporting

     Our identified reportable segments are primarily based on geographic areas, both domestically and abroad. On February 2, 2006 we acquired NRG Texas creating a new segment of operations – Wholesale Power Generation – Texas.

     As of December 31, 2005, interest bearing intercompany debt was issued to certain subsidiaries in the Northeast and South Central segments that resulted in increased interest expense, thus reducing their net income for the three months ended March 31, 2006, by $14 million and $7 million, respectively. During the first quarter of 2005, such interest expense was immaterial.

		Three Months Ended March 31, 2006
		Wholesale Power Generation
																										All Other
										South								Other North								Other				Alternative				Non-
		Texas				Northeast				Central				Western				America				Australia				International				Energy				Generation				Other				Total
		(In millions)
Operations
Operating revenues		$	438			$	392			$	172			$	—			$	1			$	54			$	42			$	15			$	51			$	(21	)		$	1,144
Depreciation and amortization			74				22				15				—				2				6				1				1				3				1				125
Equity in earnings/(losses) of unconsolidated affiliates			—				—				—				(2	)			2				6				15				—				—				—				21
Income/(loss) from continuing operations before income taxes			(7	)			132				35				(4	)			59				7				24				2				13				(243	)			18
Net income/(loss) from continuing operations			18				132				35				(2	)			58				5				17				2				10				(257	)			18
Net income from discontinued operations, net of income taxes			—				—				—				—				8				—				—				—				—				—				8
Net income/(loss)		$	18			$	132			$	35			$	(2	)		$	66			$	5			$	17			$	2			$	10			$	(257	)		$	26
Total assets		$	13,044			$	1,732				964			$	432			$	233			$	851			$	591			$	46			$	894			$	720			$	19,507

		Three Months Ended March 31, 2005
		Wholesale Power Generation
																						All Other
						South								Other North								Other				Alternative				Non-
		Northeast				Central				Western				America				Australia				International				Energy				Generation				Other				Total
		(In millions)
Operations
Operating revenues		$	332			$	117			$	—			$	1			$	49			$	43			$	15			$	41			$	(1	)		$	597
Depreciation and amortization			19				15				—				2				6				1				1				3				1				48
Equity in earnings of unconsolidated affiliates			—				—				5				2				6				24				—				—				—				37
Income/(loss) from continuing operations before income taxes			33				9				3				(6	)			11				46				1				5				(75	)			27
Net income/(loss) from continuing operations			33				9				3				(6	)			10				42				1				5				(75	)			22
Net income from discontinued operations, net of income taxes			—				—				—				1				—				—				—				—				—				1
Net income/(loss)		$	33			$	9			$	3			$	(5	)		$	10			$	42			$	1			$	5			$	(75	)		$	23