Table of Contents

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: June 30, 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	 	08540	
(Address of principal executive offices)	 	(Zip Code)	
(609) 524-4500
(Registrant’s telephone number, including area code)
     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such 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 August 2, 2006, there were 137,015,810 shares of common stock outstanding, par value $0.01 per share.

 

 
TABLE OF CONTENTS
Index
 	 	 	
 	 	Page No.	
Cautionary Statement Regarding Forward Looking Information	 	3	
GLOSSARY OF TERMS	 	4	
Part I — FINANCIAL INFORMATION	 	5	
Item 1 — Condensed Consolidated Financial Statements and Notes	 	5	
Item 2 — Management’s Discussion and Analysis of Financial Condition and Results of Operations	 	48	
Item 3 — Quantitative and Qualitative Disclosures About Market Risk	 	70	
Item 4 — Controls and Procedures	 	73	
Part II — OTHER INFORMATION	 	74	
Item 1 — Legal Proceedings	 	74	
Item 1A — Risk Factors	 	74	
Item 2 — Unregistered Sales of Equity Securities and Use of Proceeds	 	74	
Item 3 — Defaults Upon Senior Securities	 	74	
Item 4 — Submission of Matters to a Vote of Security Holders	 	74	
Item 5 — Other Information	 	75	
Item 6 — Exhibits	 	75	
SIGNATURES	 	76	
Exhibit Index	 	77	
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Table of Contents
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 Energy, Inc.’s actual results, performance and achievements, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statement. These factors, risks and uncertainties include the factors described under Risks Related to NRG Energy, Inc. in Item 1A of NRG Energy, Inc.’s 2005 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 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 Energy, Inc. may not have adequate insurance to cover losses as a result of such hazards;	
 	 	 	 	
 	•	 	The effectiveness of NRG Energy Inc.’s risk management policies and procedures, and the ability of NRG Energy, Inc.’s counterparties to satisfy their financial commitments;	
 	 	 	 	
 	•	 	Counterparties’ collateral demands and other factors affecting NRG Energy, Inc.’s liquidity position and financial condition;	
 	 	 	 	
 	•	 	NRG Energy, Inc.’s ability to operate its businesses efficiently, manage capital expenditures and costs tightly (including general and administrative expenses), and generate earnings and cash flow from NRG Energy, Inc.’s asset-based businesses in relation to the Company debt and other obligations;	
 	 	 	 	
 	•	 	NRG Energy, Inc.’s 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, tariffs and environmental laws;	
 	 	 	 	
 	•	 	Price mitigation strategies and other market structures employed by independent system operators or ISO, or regional transmission organizations that result in a failure to adequately compensate the Company’s generation units for all of their costs;	
 	 	 	 	
 	•	 	NRG Energy, Inc.’s ability to borrow additional funds and access capital markets, as well as NRG Energy, Inc’s substantial indebtedness and the possibility that NRG Energy, Inc. may incur additional indebtedness going forward;	
 	 	 	 	
 	•	 	Operating and financial restrictions placed on NRG Energy, Inc. contained in the indentures governing NRG Energy Inc.’s 7.25% and 7.375% unsecured senior notes due 2014 and 2016, respectively, in NRG Energy, Inc.’s senior secured credit facility and in debt and other agreements of certain of the NRG Energy, Inc. subsidiaries and project affiliates generally; and	
 	 	 	 	
 	•	 	NRG Energy, Inc.’s ability to achieve the objectives of its development programs.	
     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 Energy, Inc.’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.
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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	
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	
CL&P	 	Connecticut Light & Power	
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 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	
Fresh Start	 	Reporting requirements as defined by SOP 90-7	
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	
MDE	 	Maryland Department of the Environment	
MWh	 	Saleable megawatt hours net of internal/parasitic load megawatt-hours	
NiMo	 	Niagara Mohawk Power Corporation	
NOx	 	Nitrogen oxides	
NOL	 	Net operating loss	
NQSO	 	Non-qualified stock option	
NYISO	 	New York Independent System Operator	
NYSDEC	 	New York Department of Environmental Conservation	
OCI	 	Other Comprehensive Income	
PJM	 	PJM Interconnection, LLC	
PJM Market	 	The wholesale and retail electric market operated by PJM primarily in all or parts of Delaware, the District of Columbia, Illinois, Maryland, New Jersey, Ohio, Pennsylvania, Virginia and West Virginia	
Powder River Basin,
or PRB Coal	 	Coal produced in the northeastern Wyoming and southeastern Montana, which has low sulfur content	
PUCT	 	Public Utility Commission of Texas	
RMR	 	Reliability must-run	
SEC	 	United States Securities and Exchange Commission	
Sellers	 	Former holders of Texas Genco LLC shares	
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 (R)	 	SFAS No. 123 (revised 2004), Share-Based Payment	
SFAS 133
SFAS 141	 	SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities
SFAS No. 141,  Business Combinations	
SFAS 142	 	SFAS No. 142, Goodwill and Other Intangible Assets	
SFAS 143	 	SFAS No. 143, Accounting for Asset Retirement Obligations	
SFAS 144	 	SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets	
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 NRG has a 44% ownership interest	
NRG Texas	 	Texas Genco LLC	
US	 	United States of America	
USEPA	 	United States Environmental Protection Agency	
US GAAP	 	Accounting principles generally accepted in the US	
WCP	 	WCP (Generation) Holdings, Inc.	
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Table of Contents
PART I — FINANCIAL INFORMATION
Item 1 — Condensed Consolidated Financial Statements and Notes
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Three months ended June 30	 	 	Six months ended June 30	 	
(In millions, except for per share amounts)	 	2006	 	 	2005	 	 	2006	 	 	2005	 	
 	
Operating Revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues from majority-owned operations	 	$	1,423	 	 	$	522	 	 	$	2,513	 	 	$	1,070	 	
 	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cost of majority-owned operations	 	 	746	 	 	 	387	 	 	 	1,447	 	 	 	796	 	
Depreciation and amortization	 	 	178	 	 	 	41	 	 	 	297	 	 	 	83	 	
General, administrative and development	 	 	83	 	 	 	50	 	 	 	143	 	 	 	97	 	
Corporate relocation charges	 	 	—	 	 	 	1	 	 	 	—	 	 	 	4	 	
 	
Total operating costs and expenses	 	 	1,007	 	 	 	479	 	 	 	1,887	 	 	 	980	 	
 	
Operating Income	 	 	416	 	 	 	43	 	 	 	626	 	 	 	90	 	
 	
Other Income (Expense)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Equity in earnings of unconsolidated affiliates	 	 	8	 	 	 	16	 	 	 	29	 	 	 	53	 	
Write downs and gains on sales of equity method investments	 	 	14	 	 	 	12	 	 	 	11	 	 	 	12	 	
Other income, net	 	 	8	 	 	 	6	 	 	 	88	 	 	 	31	 	
Refinancing expense	 	 	—	 	 	 	—	 	 	 	(178	)	 	 	(35	)	
Interest expense	 	 	(152	)	 	 	(46	)	 	 	(266	)	 	 	(98	)	
 	
Total other expense	 	 	(122	)	 	 	(12	)	 	 	(316	)	 	 	(37	)	
 	
Income From Continuing Operations Before Income Taxes	 	 	294	 	 	 	31	 	 	 	310	 	 	 	53	 	
Income Tax Expense	 	 	90	 	 	 	8	 	 	 	89	 	 	 	14	 	
 	
Income From Continuing Operations	 	 	204	 	 	 	23	 	 	 	221	 	 	 	39	 	
Income/(loss) from discontinued operations, net of income tax expense/(benefit)	 	 	(1	)	 	 	1	 	 	 	8	 	 	 	8	 	
 	
Net Income	 	 	203	 	 	 	24	 	 	 	229	 	 	 	47	 	
Dividends for Preferred Shares	 	 	13	 	 	 	4	 	 	 	23	 	 	 	8	 	
 	
Income Available for Common Stockholders	 	$	190	 	 	$	20	 	 	$	206	 	 	$	39	 	

Weighted Average Number of Common Shares Outstanding — Basic	 	 	137	 	 	 	87	 	 	 	127	 	 	 	87	 	
Income From Continuing Operations per Weighted Average Common Share — Basic	 	$	1.39	 	 	$	0.22	 	 	$	1.55	 	 	$	0.35	 	
Income/(loss) From Discontinued Operations per Weighted Average Common Share — Basic	 	 	(0.01	)	 	 	0.01	 	 	 	0.06	 	 	 	0.09	 	
 	
Net Income per Weighted Average Common Share — Basic	 	$	1.38	 	 	$	0.23	 	 	$	1.61	 	 	$	0.44	 	

Weighted Average Number of Common Shares Outstanding — Diluted	 	 	159	 	 	 	88	 	 	 	148	 	 	 	88	 	
Income From Continuing Operations per Weighted Average Common Share — Diluted	 	$	1.26	 	 	$	0.21	 	 	$	1.47	 	 	$	0.34	 	
Income/(loss) From Discontinued Operations per Weighted Average Common Share — Diluted	 	 	—	 	 	 	0.01	 	 	 	0.05	 	 	 	0.09	 	
 	
Net Income per Weighted Average Common Share — Diluted	 	$	1.26	 	 	$	0.22	 	 	$	1.52	 	 	$	0.43	 	
 	
See notes to condensed consolidated financial statements.
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Table of Contents
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
 	 	 	 	 	 	 	 	 	 	
 	 	June 30,	 	 	December 31,	 	 	
 	 	2006	 	 	2005	 	 	
(in millions, except shares and par value)	 	(unaudited)	 	 	 	 	 	 	
 	
ASSETS	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	957	 	 	$	493	 	 	 	 	 	 	 	 	 	
Restricted cash	 	 	58	 	 	 	49	 	 	 	 	 	 	 	 	 	
Accounts receivable, less allowance for doubtful accounts of $2 and $2	 	 	473	 	 	 	259	 	 	 	 	 	 	 	 	 	
Inventory	 	 	402	 	 	 	242	 	 	 	 	 	 	 	 	 	
Derivative instruments valuation	 	 	528	 	 	 	387	 	 	 	 	 	 	 	 	 	
Collateral on deposits in support of energy risk management activities	 	 	209	 	 	 	438	 	 	 	 	 	 	 	 	 	
Prepayments and other current assets	 	 	187	 	 	 	188	 	 	 	 	 	 	 	 	 	
Current assets — held-for-sale	 	 	—	 	 	 	43	 	 	 	 	 	 	 	 	 	
Current assets — discontinued operations	 	 	96	 	 	 	98	 	 	 	 	 	 	 	 	 	
 	
Total current assets	 	 	2,910	 	 	 	2,197	 	 	 	 	 	 	 	 	 	
 	
Property, plant and equipment, net of accumulated depreciation of $668 and $343	 	 	11,815	 	 	 	2,620	 	 	 	 	 	 	 	 	 	
 	
Other Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Equity investments in affiliates	 	 	307	 	 	 	603	 	 	 	 	 	 	 	 	 	
Notes receivable, less current portion	 	 	480	 	 	 	458	 	 	 	 	 	 	 	 	 	
Goodwill	 	 	1,462	 	 	 	—	 	 	 	 	 	 	 	 	 	
Intangible assets, net of accumulated amortization of $131and $79	 	 	1,182	 	 	 	257	 	 	 	 	 	 	 	 	 	
Nuclear decommissioning trust fund	 	 	326	 	 	 	—	 	 	 	 	 	 	 	 	 	
Derivative instruments valuation	 	 	191	 	 	 	18	 	 	 	 	 	 	 	 	 	
Funded letter of credit	 	 	—	 	 	 	350	 	 	 	 	 	 	 	 	 	
Deferred income taxes	 	 	42	 	 	 	26	 	 	 	 	 	 	 	 	 	
Other non-current assets	 	 	242	 	 	 	124	 	 	 	 	 	 	 	 	 	
Intangible assets held-for-sale	 	 	66	 	 	 	—	 	 	 	 	 	 	 	 	 	
Non-current assets — discontinued operations	 	 	419	 	 	 	813	 	 	 	 	 	 	 	 	 	
 	
Total other assets	 	 	4,717	 	 	 	2,649	 	 	 	 	 	 	 	 	 	
 	
Total Assets	 	$	19,442	 	 	$	7,466	 	 	 	 	 	 	 	 	 	

LIABILITIES AND STOCKHOLDERS’ EQUITY	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current Liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current portion of long-term debt and capital leases	 	$	125	 	 	$	95	 	 	 	 	 	 	 	 	 	
Accounts payable	 	 	340	 	 	 	247	 	 	 	 	 	 	 	 	 	
Derivative instruments valuation	 	 	640	 	 	 	679	 	 	 	 	 	 	 	 	 	
Accrued expenses and other current liabilities	 	 	467	 	 	 	174	 	 	 	 	 	 	 	 	 	
Current liabilities — discontinued operations	 	 	58	 	 	 	162	 	 	 	 	 	 	 	 	 	
 	
Total current liabilities	 	 	1,630	 	 	 	1,357	 	 	 	 	 	 	 	 	 	
 	
Other Liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term debt and capital leases	 	 	7,631	 	 	 	2,410	 	 	 	 	 	 	 	 	 	
Nuclear decommissioning reserve	 	 	226	 	 	 	—	 	 	 	 	 	 	 	 	 	
Nuclear decommissioning trust liability	 	 	325	 	 	 	—	 	 	 	 	 	 	 	 	 	
Deferred income taxes	 	 	152	 	 	 	129	 	 	 	 	 	 	 	 	 	
Derivative instruments valuation	 	 	398	 	 	 	56	 	 	 	 	 	 	 	 	 	
Out-of-market contracts	 	 	2,320	 	 	 	298	 	 	 	 	 	 	 	 	 	
Other non-current liabilities	 	 	378	 	 	 	170	 	 	 	 	 	 	 	 	 	
Non-current liabilities — discontinued operations	 	 	278	 	 	 	568	 	 	 	 	 	 	 	 	 	
 	
Total non-current liabilities	 	 	11,708	 	 	 	3,631	 	 	 	 	 	 	 	 	 	
 	
Total Liabilities	 	 	13,338	 	 	 	4,988	 	 	 	 	 	 	 	 	 	
 	
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; 136,979,082 and 80,701,888 outstanding	 	 	1	 	 	 	1	 	 	 	 	 	 	 	 	 	
Additional paid-in capital	 	 	4,454	 	 	 	2,431	 	 	 	 	 	 	 	 	 	
Retained earnings	 	 	374	 	 	 	261	 	 	 	 	 	 	 	 	 	
Less treasury stock, at cost — 0 and 19,346,788 shares	 	 	—	 	 	 	(663	)	 	 	 	 	 	 	 	 	
Accumulated other comprehensive income/(loss)	 	 	136	 	 	 	(205	)	 	 	 	 	 	 	 	 	
 	
Total stockholders’ equity	 	 	5,857	 	 	 	2,231	 	 	 	 	 	 	 	 	 	
 	
Total Liabilities and Stockholders’ Equity	 	$	19,442	 	 	$	7,466	 	 	 	 	 	 	 	 	 	
 	
See notes to condensed consolidated financial statements.
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Table of Contents
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 	 	 	 	 	 	 	 	 	
 	 	Six months ended June 30	 	
(In millions)	 	2006	 	 	2005	 	
 	
Cash Flows from Operating Activities	 	 	 	 	 	 	 	 	
Net income	 	$	229	 	 	$	47	 	
Adjustments to reconcile net income to net cash provided by operating activities	 	 	 	 	 	 	 	 	
Distributions in excess of equity in earnings of unconsolidated affiliates	 	 	(13	)	 	 	16	 	
Depreciation and amortization	 	 	308	 	 	 	96	 	
Amortization of financing costs and debt discount	 	 	16	 	 	 	5	 	
Amortization of intangibles and out-of-market contracts	 	 	(211	)	 	 	15	 	
Amortization of unearned equity compensation	 	 	9	 	 	 	5	 	
Write-off of deferred financing costs and debt premium	 	 	47	 	 	 	(8	)	
Write down and gains on sale of equity method investments	 	 	(11	)	 	 	(12	)	
Deferred income taxes	 	 	96	 	 	 	(4	)	
Nuclear decommissioning trust liability	 	 	3	 	 	 	—	 	
Minority interest	 	 	—	 	 	 	1	 	
Loss on sale of equipment	 	 	3	 	 	 	—	 	
Unrealized (gains)/losses on derivatives	 	 	(114	)	 	 	82	 	
Gain on legal settlement	 	 	(67	)	 	 	(14	)	
Gain on sale of discontinued operations	 	 	(10	)	 	 	—	 	
Gain on sale of emission allowances	 	 	(67	)	 	 	—	 	
Collateral deposit payments in support of energy risk management activities	 	 	272	 	 	 	(179	)	
Cash provided by changes in other working capital, net of acquisition and disposition affects	 	 	114	 	 	 	41	 	
 	
Net Cash Provided by Operating Activities	 	 	604	 	 	 	91	 	
Cash Flows from Investing Activities	 	 	 	 	 	 	 	 	
Acquisition of Texas Genco LLC, net of cash acquired	 	 	(4,303	)	 	 	—	 	
Acquisition of WCP, net of cash acquired	 	 	(25	)	 	 	—	 	
Decrease/(Increase) in restricted cash and trust funds, net	 	 	(9	)	 	 	26	 	
Decrease in notes receivable	 	 	14	 	 	 	93	 	
Investments in nuclear decommissioning trust fund securities	 	 	(106	)	 	 	—	 	
Purchases of emission allowances	 	 	(78	)	 	 	—	 	
Sales of emission allowances	 	 	84	 	 	 	—	 	
Proceeds from sale of equipment	 	 	1	 	 	 	—	 	
Proceeds on sale of investments	 	 	86	 	 	 	65	 	
Proceeds on sale of discontinued operations	 	 	15	 	 	 	—	 	
Proceeds from sales of nuclear decommissioning trust fund securities	 	 	103	 	 	 	—	 	
Return of capital from equity method investments and projects	 	 	—	 	 	 	1	 	
Capital expenditures	 	 	(74	)	 	 	(37	)	
 	
Net Cash Provided/(Used) by Investing Activities	 	 	(4,292	)	 	 	148	 	
Cash Flows from Financing Activities	 	 	 	 	 	 	 	 	
Payment of dividends to preferred stockholders	 	 	(23	)	 	 	(8	)	
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, net	 	 	7,175	 	 	 	204	 	
Principal payments on short and long-term debt	 	 	(4,662	)	 	 	(722	)	
 	
Net Cash Provided/(Used) by Financing Activities	 	 	4,148	 	 	 	(527	)	
 	
Change in Cash from Discontinued Operations	 	 	1	 	 	 	(3	)	
Effect of Exchange Rate Changes on Cash and Cash Equivalents	 	 	3	 	 	 	(1	)	
 	
Net Increase (Decrease) in Cash and Cash Equivalents	 	 	464	 	 	 	(292	)	
Cash and Cash Equivalents at Beginning of Period	 	 	493	 	 	 	1,071	 	
 	
Cash and Cash Equivalents at End of Period	 	$	957	 	 	$	779	 	
 	
See notes to condensed consolidated financial statements.
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NRG ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1 — Basis of Presentation
     NRG Energy, Inc., “NRG”, “we”, “us” or the “Company”, 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.
     The accompanying unaudited interim condensed 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 1,  Summary of Significant Accounting Policies,  to the Company’s financial statements in its Annual Report on Form 10-K for the year ended December 31, 2005. The following notes should be read in conjunction with such policies and other disclosures in the Form 10-K for the fiscal year ended December 31, 2005. Interim results are not necessarily indicative of results for a full year.
     In the opinion of management, the accompanying unaudited interim condensed consolidated financial statements contain all material adjustments (consisting of normal, recurring accruals) necessary to fairly present NRG’s consolidated financial position as of June 30, 2006, the results of NRG’s operations for the three months and six months ended June 30, 2006 and 2005, and NRG’s cash flows for the six months ended June 30, 2006 and 2005. 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.
Emission Allowances
     NRG actively manages its SO2 emission allowances as well as fuels and accounts for this asset optimization activity related to emission allowances and other fuel commodities under EITF Issue No. 02-3,  Accounting for Contracts Involved in Energy Trading and Risk Management Activities . As such, revenues and costs for these activities are reflected on a net basis in the consolidated statement of operations. Emission allowances allocated for trading are considered to be intangible assets held for sale and are valued at the lower of their weighted average cost or market. In accordance with their classification as intangible assets, purchases and sales of emissions allowances are classified as an investing activity with the corresponding gains and/or losses on the sales recorded as an adjustment to operating activity in the consolidated statement of cash flows.
Goodwill and Intangible Assets
     Goodwill is the excess of the purchase price of an acquired business over the fair value of the net assets acquired. NRG accounts for goodwill and other intangibles under the provisions of SFAS 142,  Goodwill and Other Intangible Assets,  and consequently NRG does not amortize goodwill. SFAS 142 requires us to evaluate goodwill and other intangibles for impairment at least annually or more often if events and circumstances such as adverse changes in the business climate, indicate there maybe impairment. Goodwill is impaired if the carrying value of the business exceeds its fair value. Annually, NRG estimates the fair value of the businesses the Company has acquired using estimated future cash flows or other methods to assess fair value. If the estimated fair value of the business is less than its carrying value, an impairment loss is required to be recognized to the extent that the carrying value of goodwill is greater than its fair value. SFAS 142 also requires the amortization of intangible assets with finite lives.
New Accounting Pronouncements
     NRG adopted SFAS 123(R) and Staff Accounting Bulletin 107, or SAB 107, on January 1, 2006 under a modified version of prospective application, or the modified prospective method. Under the modified prospective method, NRG applied the provisions of SFAS 123(R) to new awards of stock-based compensation and to awards modified, repurchased, or cancelled after the required effective date. SFAS 123(R) requires that NRG apply a forfeiture rate to existing awards and to calculate the retroactive impact of such application. If material, NRG must recognize in income the cumulative effect of this as a change in accounting principle as of the required effective date. Upon adoption of SFAS 123(R) on January 1, 2006, NRG applied a forfeiture rate to the Company’s existing awards and recognized in income approximately $1.1 million (net of tax of $0.8 million) as a reduction to compensation expense for
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the six months ended June 30, 2006. This amount did not materially affect the Company’s consolidated financial position, results of operations or statement of cash flows for the six months ended June 30, 2006.
     On January 1, 2006, NRG adopted EITF Issue No. 04-6 Accounting for Stripping Costs Incurred during Production in the Mining Industry , or EITF 04-6. EITF 04-6 provides that costs incurred to remove overburden and waste material to access coal seams, or stripping costs; during the production phase of a mine are variable production costs that should be included in the costs of the inventory produced during the period that the stripping costs are incurred. EITF 04-6 is effective for the first reporting period in fiscal years beginning after December 15, 2005. MIBRA GmbH, or MIBRAG, in which NRG holds a 50% equity investment, has mining operations which were negatively affected by this pronouncement. As of December 31, 2005, MIBRAG had capitalized costs totaling approximately $185 million (€157 million), representing the stripping costs incurred during production as of December 31, 2005. As a result of the Adoption of EITF 04-6, such costs are no longer allowed to be capitalized and in accordance with the new pronouncement, were written off to retained earnings. The adoption of EITF 04-6 did not have a material impact on NRG’s consolidated results of operations, but did have a material impact on NRG’s consolidated financial position. Following adoption on January 1, 2006, NRG’s investment in MIBRAG was reduced by 50% of the above mentioned asset, approximately $93 million after tax, with an offsetting charge to retained earnings.
     On January 1, 2006, NRG 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 No. 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, NRG recognized additional equity in earnings of unconsolidated affiliates of approximately $2.1 million, after tax, from the Company’s MIBRAG interest. This amount reflects the cumulative effect of the adoption of EITF 05-5, and did not materially affect NRG’s consolidated financial position, results of operations or statement of cash flows for the period ending June 30, 2006.
     During the first quarter of 2006, the FASB issued SFAS No. 155 Accounting for Certain Hybrid Financial Instruments — an amendment of FASB Statements Nos. 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. NRG does not expect this guidance to materially affect the Company’s consolidated financial position, results of operations or statement of cash flows.
     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. FIN 48 prescribes a comprehensive model for recognizing, measuring, presenting and disclosing in the financial statements tax positions taken or expected to be taken on a tax return, including a decision as to whether to file or not to file in a particular jurisdiction. FIN 48 is effective for fiscal years beginning after December 15, 2006. If there are changes in net assets as a result of application of FIN 48 these are to be accounted for as an adjustment to retained earnings. NRG is currently assessing the impact of FIN 48 on its consolidated financial position.
Note 2 — Comprehensive Income/(Loss)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Three months ended June 30	 	 	Six months ended June 30	 	
(In millions)	 	2006	 	 	2005	 	 	2006	 	 	2005	 	
 	
Net Income	 	$	203	 	 	$	24	 	 	$	229	 	 	$	47	 	
Unrealized gain/(loss) from derivative activity	 	 	57	 	 	 	(4	)	 	 	304	 	 	 	(86	)	
Foreign currency translation adjustment	 	 	34	 	 	 	(27	)	 	 	37	 	 	 	(50	)	
 	
Other comprehensive income/(loss), net of tax	 	$	91	 	 	$	(31	)	 	$	341	 	 	$	(136	)	

Comprehensive income/(loss)	 	$	294	 	 	$	(7	)	 	$	570	 	 	$	(89	)	
 	
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     Accumulated other comprehensive income/ (loss) as of June 30, 2006 was as follows:
 	 	 	 	 	
(In millions) As of June 30	 	2006	 	
 	 	 	 	
Accumulated other comprehensive loss as of December 31, 2005	 	$	(205	)	
Unrealized gain from derivative activity	 	 	304	 	
Foreign currency translation adjustments	 	 	37	 	
 	 	 	 	
Accumulated other comprehensive income as of June 30, 2006	 	$	136	 	
 	 	 	 	
Note 3 — Business Acquisitions and Dispositions
Acquisition of Texas Genco LLC and Related Financing
     On February 2, 2006, NRG acquired Texas Genco LLC, 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 NRG’s common stock issued to the Sellers was based on NRG’s 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 and related financing activities were funded at closing with a combination of (i) cash proceeds received upon the issuance and sale in a public offering of 20,855,057 shares of NRG’s 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 2,000,000 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 $3.6 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 at NRG Texas is 10,776 MW, which includes 5,296 MW of low marginal cost solid fuel and nuclear powered baseload plants. Similar to the rest of NRG, NRG Texas is a wholesale power 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.
     The acquisition of Texas Genco LLC was accounted for using the purchase method of accounting and, accordingly, the purchase price was allocated to the assets acquired and liabilities assumed based on the estimated fair value of such assets and liabilities as of February 2, 2006. Since it is difficult to estimate an allocation of the purchase price without completed asset appraisals, NRG has 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 the allocation between the preliminary assessed goodwill and plant or other intangibles would result in a change in 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.
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     The following table summarizes the preliminary fair value of the assets acquired and liabilities assumed at the date of the acquisition. For purposes of acquisition costs, NRG has estimated acquisition costs of approximately $129 million, thereby, increasing the total purchase price to approximately $6.2 billion.
 	 	 	 	 	
(In millions) As of February 2,	 	2006	 	
 	 	 	 	
Assets	 	 	 	 	
Current and non-current assets	 	$	830	 	
Coal inventory	 	 	33	 	
In-market contracts	 	 	 	 	
Power contracts	 	 	39	 	
Water contracts	 	 	64	 	
Coal contracts	 	 	100	 	
Nuclear fuel contracts	 	 	48	 	
SO2 emission allowances	 	 	530	 	
NOx emission allowances	 	 	320	 	
Property, plant and equipment	 	 	9,348	 	
Deferred tax asset	 	 	1,560	 	
Goodwill	 	 	1,462	 	
 	 	 	 	
Total assets acquired	 	 	14,334	 	

Liabilities	 	 	 	 	
Current and non-current liabilities	 	 	872	 	
Pension and post-retirement liability	 	 	213	 	
Out-of-market contracts:	 	 	 	 	
Coal	 	 	150	 	
Gas swaps	 	 	472	 	
Power contracts	 	 	2,100	 	
Deferred tax liability	 	 	1,560	 	
Long term debt	 	 	2,735	 	
 	 	 	 	
Total liabilities assumed	 	 	8,102	 	
 	 	 	 	
Net assets acquired	 	$	6,232	 	
 	 	 	 	
     The value of goodwill is still subject to change as the Company is still in the process of valuing all assets and liabilities acquired. NRG is 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 following table summarizes the change in the value of goodwill during the three month period ended June 30, 2006:
 	 	 	 	 	
(In millions)	 	 	 	 	
 	
Goodwill balance at March 31, 2006	 	$	2,748	 	
Increase in fixed assets per valuation	 	 	(918	)	
Net decrease in intangibles and other contracts per valuation	 	 	256	 	
Adjustment to deferred tax assets and liabilities	 	 	(624	)	
 	 	 	 	
Impact to goodwill due to changes in valuation	 	 	(1,286	)	
 	 	 	 	
Goodwill balance at June 30, 2006	 	$	1,462	 	
 	 	 	 	
     The changes in value for fixed assets, identifiable intangibles and deferred taxes are due to several factors, including the following:
 	•	 	Changes in the forecasted projected price of electricity, coal and emission allowances;	
 	 	 	 	
 	•	 	The tax basis of the assets and liabilities acquired is more accurate, but still subject to revision; and	
 	 	 	 	
 	•	 	More precise information with respect to identifiable tangible and intangibles assets.	
     Currently, NRG has valued goodwill at approximately $1.5 billion. NRG’s preliminary appraisal of Property, Plant and Equipment increased its fair value, compared to Texas Genco LLC’s historical cost, by approximately $5.7 billion. If the remaining goodwill balance is indicative of a further increase in value of depreciable property plant and equipment, depreciation expense for the three months and six months ended June 30, 2006 would increase by approximately $21 million and $35 million, respectively, reducing income from continuing operations before tax for the three and six months ended June 30, 2006 to approximately $273 million and $275 million, respectively.
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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 capacity 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, NRG wrote down the Company’s investment in Rocky Road by approximately $20 million to reflect the 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 was accounted for as a step acquisition as the Company’s 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 of the percentage of net assets acquired at the date of each transaction.
     NRG’s consolidated balance sheet as of June 30, 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 forecasted prices and an analysis of the income tax effect of the acquisition.
     The following summarizes the preliminary purchase price and allocation impact of the WCP acquisition as of March 31, 2006:
 	 	 	 	 	
(In millions) As of March 31,	 	2006	 	
 	 	 	 	
Current assets	 	$	296	 	
Property, plant and equipment	 	 	81	 	
Intangible assets	 	 	15	 	
Current liabilities	 	 	(25	)	
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 June 30	 	 	Six months ended June 30	 	
(In millions)	 	2005	 	 	2006	 	 	2005	 	
 	 	 	 	 	 	 	 	 	 	
Operating revenues	 	$	1,134	 	 	$	2,771	 	 	$	2,351	 	
Net income/(loss)	 	 	125	 	 	 	(97	)	 	 	188	 	
Earnings/(loss) per share — Basic	 	 	0.99	 	 	 	(0.91	)	 	 	1.47	 	
Earnings/(loss) per share — Diluted	 	 	0.98	 	 	 	(0.91	)	 	 	1.46	 	
Weighted average number of shares outstanding — Basic	 	 	122.4	 	 	 	133.6	 	 	 	122.4	 	
Weighted average number of shares outstanding — Diluted	 	 	123.1	 	 	 	133.6	 	 	 	123.1	 	
 	 	 	 	 	 	 	 	 	 	
     The pro forma net loss for the six months ended June 30, 2006 reflects 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	 	
 	 	 	 	
Other Business Events
     Padoma — On July 14, 2006, NRG announced the completion of the acquisition of privately-held Padoma Wind Power LLC, or Padoma, a wind farm developer, whose principals have developed, financed, built and operated more than 40 wind farms in the U.S. and Europe. Padoma will maintain its headquarters in La Jolla, California and will operate as a subsidiary of NRG.
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     Gladstone — On June 8, 2006, NRG announced the sale of the Company’s 37.5% equity interest in the Gladstone power station, or Gladstone, and its associated 100% owned NRG Gladstone Operating Services to Transfield Services, an Australia-based provider of operations, maintenance, ownership and asset management services for a purchase price of approximately $174 million (AU$239 million) subject to customary purchase price adjustments, plus assumption of NRG’s share of Gladstone’s unconsolidated debt and cash of approximately $56 million (AU$ 77 million) and approximately $26 million (AU$35 million), respectively. After tax cash proceeds are expected to be in excess of $171 million (AU$ 234 million). NRG is seeking to close the transaction during the fourth quarter of 2006, but considerable uncertainty remains over NRG’s ability to satisfy certain conditions particularly the securing of certain consents and waivers from the other owners of the project. As a result, NRG Gladstone Operating Services has not been classified as discontinued operations.
     Flinders — On June 1, 2006, NRG entered into a sale and purchase agreement to sell its 100% owned Flinders power station and related assets or Flinders, located near Port Augusta, Australia to Babcock & Brown Power Pty, a subsidiary of Babcock & Brown, a global investment and advisory firm, for a purchase price of approximately $231 million (AU$317 million), subject to customary purchase price adjustments, plus the assumption of approximately $174 million (AU$238 million) of non-recourse debt obligations and approximately $31 million (AU$42 million) in cash. The sale is subject to customary approvals, including third party approvals. NRG anticipates closing the transaction during the third quarter of 2006.
     Audrain — On March 29, 2006, NRG completed the sale of the Audrain generating station, a gas-fired peaking facility in Vandalia, Missouri, to AmerenUE, a subsidiary of Ameren Corporation. The purchase price was $115 million, subject to customary purchase price adjustments, plus AmerenUE’s assumption of $240 million of non-recourse capital lease obligations and assignment of a $240 million note receivable. Of the $115 million in cash proceeds, approximately $20 million was paid to NRG. The sale process removed approximately $412 million of assets and liabilities. Of this amount, $355 million remained on NRG’s balance sheet as of December 31, 2005, categorized as discontinued operations.
     As further discussed in Note 4 below, the activities of Flinders and Audrain have been classified as discontinued operations.
Note 4 — Discontinued Operations
     NRG has classified certain business operations, and gains/(losses) recognized on sale, as discontinued operations for businesses 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, NRG’s management considered cash flow analysis and offers related to the assets and businesses. This amount is included in income/(loss) from discontinued operations, net of income taxes in the accompanying condensed 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 disposed operations of entities discussed in Note 3. Total cash proceeds received were approximately $115 million for both the three and six months ended June 30, 2006. There were no cash proceeds received for the three and six months ended 2005. A gain on the sale of Audrain of approximately $10 million was recognized for the three and six months ended of June 30, 2006. There were no gain or loss on the sale of discontinued operations for the three and six months ended June 30, 2005.
     For the three and six months ended June 30, 2006, discontinued operations consisted of activity related to Flinders and Audrain as noted above. For the three and six months ended June 30, 2005, discontinued operations consisted of activity related to Flinders, Audrain and NRG McClain.
     Summarized results of operations of discontinued operations were as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Three months ended June 30	 	 	Six months ended June 30	 	
(In millions)	 	2006	 	 	2005	 	 	2006	 	 	2005	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues	 	$	57	 	 	$	63	 	 	$	111	 	 	$	116	 	
Pre-tax income/(loss) from operations of discontinued operations	 	 	(3	)	 	 	2	 	 	 	(3	)	 	 	7	 	
Income/(loss) from discontinued operations, net of income taxes	 	 	(1	)	 	 	1	 	 	 	8	 	 	 	8	 	
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Note 5 — Write Downs and Gains/(Losses) on Sales of Equity Method Investments
     Write downs and gains/(losses) on sales of equity method investments recorded in the condensed consolidated statement of operations include the following:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Three months ended June 30	 	 	Six months ended June 30	 	
(In millions)	 	2006	 	 	2005	 	 	2006	 	 	2005	 	
 	 	
Latin American funds or SLAP	 	$	3	 	 	$	—	 	 	$	3	 	 	$	—	 	
James River	 	 	—	 	 	 	—	 	 	 	(3	)	 	 	—	 	
Cadillac	 	 	11	 	 	 	—	 	 	 	11	 	 	 	—	 	
Enfield	 	 	—	 	 	 	12	 	 	 	—	 	 	 	12	 	
 	 	
Total write downs and gains on sales of equity method investments	 	$	14	 	 	$	12	 	 	$	11	 	 	$	12	 	
 	 	
     SLAP — On June 30, 2006, NRG, through its wholly-owned entities NRG Caymans-C and NRG Caymans-P completed the sale of its remaining interests in various Latin American power funds to a subsidiary of Australia Post. Total proceeds received were approximately $22.6 million and a pre-tax gain of approximately $2.9 million was recognized in the second quarter of 2006.
     James River — On May 15, 2006, NRG completed the sale of Capistrano Cogeneration Company, a subsidiary of NRG which owned a 50% interest in James River to Cogentrix. The proceeds from the sale were approximately $8 million. During the first quarter of 2006, NRG wrote down the value of its equity investment in James River by approximately $3 million. The sale resulted in no gain or loss to NRG.
     Cadillac — On January 1, 2006, NRG sold its 49.5% interest in a 38MW biomass fuel 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, resulting in a pre-tax gain of approximately $11 million.
Note 6 — Investments Accounted for by the Equity Method
     As of December 31, 2005, NRG had a 50% interest in both MIBRAG and WCP, which were considered significant, as defined by applicable SEC regulations. As discussed in Note 3, NRG acquired the remaining 50% interest in WCP on March 31, 2006 and no longer qualified for accounting per the equity method. As of June 30, 2006, the only equity investment which was considered significant was NRG’s 50% interest in MIBRAG.
MIBRAG Summarized Financial Information
     For the three and six months ended June 30, 2006, NRG recorded equity earnings for MIBRAG of $2 million and $14 million, respectively. For the three months ended June 30, 2005 NRG recorded equity earnings for MIBRAG of a loss of $1 million but recorded a gain of $8 million for the six months ended June 30, 2005. The following table summarizes the results of operations for MIBRAG, including interests owned by NRG and other parties for the periods shown below:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Three months ended June 30	 	 	Six months ended June 30	 	
Results of Operations (in millions)	 	2006	 	 	2005	 	 	2006	 	 	2005	 	
 	 	
Operating revenues	 	$	105	 	 	$	92	 	 	$	214	 	 	$	204	 	
Operating income	 	 	9	 	 	 	4	 	 	 	39	 	 	 	26	 	
Net income	 	 	5	 	 	 	—	 	 	 	29	 	 	 	16	 	
 	 	
     As discussed in Note 1, NRG adopted EITF 04-6 as of January 1, 2006, which negatively affected NRG’s equity investment in MIBRAG. As of December 31, 2005, MIBRAG had an asset which totaled approximately $185 million (€157 million), this represented 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, NRG’s investment in MIBRAG has been reduced by 50% of the above mentioned asset, approximately $93 million after tax, with an offsetting charge to retained earnings.
Note 7 — Accounting for Derivative Instruments and Hedging Activities
     SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities or SFAS 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, NRG may be able to designate the Company’s derivatives as cash flow hedges and defer the effective
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portion of the change in fair value of the derivatives in 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 derivative and the hedged item are recorded in current earnings. The ineffective portion of a hedging derivative instrument’s change in fair value will be immediately recognized in earnings.
     For derivatives that are neither designated as cash flow hedges nor qualify for hedge accounting treatment, the changes in the fair value will be immediately recognized in earnings. Under the guidelines established by SFAS 133, as amended, certain derivative instruments may qualify for the normal purchase and sale exception and are therefore exempt from fair value accounting treatment. SFAS 133 applies to NRG’s energy related commodity contracts, interest rate swaps and foreign exchange contracts.
     As the Company engages principally in the trading and marketing of its generation assets, most of NRG’s commercial activities qualify for hedge accounting under the requirements of SFAS 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 the Company’s 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 the Company’s base-load coal units will normally qualify for hedge accounting treatment and any fair value movements will be reflected in the balance sheets as part of OCI.
Derivative Impact to 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 June 30, 2006:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Energy	 	 	Interest	 	 	 	 	
(In millions)	 	Commodities	 	 	Rate	 	 	Total	 	
 	 	
Accumulated OCI balance at March 31, 2006	 	$	3	 	 	$	48	 	 	$	51	 	
Realized from OCI during the period:	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
— Due to realization of previously deferred amounts	 	 	20	 	 	 	(1	)	 	 	19	 	
Mark-to-market of hedge contracts (net of tax)	 	 	6	 	 	 	32	 	 	 	38	 	
 	 	
Accumulated OCI balance at June 30, 2006	 	$	29	 	 	$	79	 	 	$	108	 	
 	 	
Gains/(Losses) expected to be realized from OCI during the next 12 months	 	$	(16	)	 	$	2	 	 	$	(14	)	
 	 	
     The following table summarizes the effects of SFAS 133 on NRG’s OCI balance attributable to hedged derivatives for the six months ended June 30, 2006:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	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	 	 	11	 	 	 	(3	)	 	 	8	 	
Mark-to-market of hedge contracts (net of tax)	 	 	222	 	 	 	74	 	 	 	296	 	
 	 	
Accumulated OCI balance at June 30, 2006	 	$	29	 	 	$	79	 	 	$	108	 	
 	 	
     The following table summarizes the effects of SFAS 133 on NRG’s OCI balance attributable to hedged derivatives for the three months ended June 30, 2005:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Energy	 	Interest	 	 	
(In millions)	 	Commodities	 	Rate	 	Total	
 	 	
Accumulated OCI balance at March 31, 2005	 	$	(88	)	 	$	13	 	 	$	(75	)	
Realized from OCI during the period:	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
— Due to realization of previously deferred amounts	 	 	1	 	 	 	—	 	 	 	1	 	
Mark-to-market of hedge contracts (net of tax)	 	 	10	 	 	 	(15	)	 	 	(5	)	
 	 	
Accumulated OCI balance at June 30, 2005	 	$	(77	)	 	$	(2	)	 	$	(79	)	
 	 	
     The following table summarizes the effects of SFAS 133 on NRG’s OCI balance attributable to hedged derivatives for the six months ended June 30, 2005:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Energy	 	 	Interest	 	 	 	 	
(In millions)	 	Commodities	 	 	Rate	 	 	Total	 	
 	 	
Accumulated OCI balance at December 31, 2004	 	$	5	 	 	$	2	 	 	$	7	 	
Realized from OCI during the period:	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
— Due to realization of previously deferred amounts	 	 	(2	)	 	 	1	 	 	 	(1	)	
Mark-to-market of hedge contracts (net of tax)	 	 	(80	)	 	 	(5	)	 	 	(85	)	
 	 	
Accumulated OCI balance at June 30, 2005	 	$	(77	)	 	$	(2	)	 	$	(79	)	
 	 	
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     Losses of $19 million and $8 million were reclassified from OCI to current period earnings during the three and six months ended June 30, 2006, respectively, compared to a loss of $1 million and a gain of $1 million during the three and six months ended June 30, 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 hedged items are recorded. Also during the three and six months ended June 30, 2006, the Company recorded gains in OCI of approximately $38 million and $296 million, respectively, compared to losses of $6 million and $85 million for the three and six months ended June 30, 2005, respectively, related to changes in the fair values of derivatives accounted for as hedges. The net balance in OCI relating to SFAS 133 as of June 30, 2006 was an unrecognized gain of approximately $108 million. Over the next 12 months it is expected that $14 million of net losses recorded in OCI at June 30, 2006, will be recognized in earnings.
Derivative Impact to the Statement of Operations
     The following table summarizes the pre-tax effects of non-hedge derivatives and derivative activities that do not qualify as hedges on NRG’s statement of operations for the three months ended June 30, 2006:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Energy	 	 	 	 	 	 	 	
(In millions)	 	Commodities	 	 	Interest Rate	 	 	Total	 	
 	 	
Revenue from majority-owned subsidiaries	 	$	67	 	 	$	—	 	 	$	67	 	
Equity in earnings of unconsolidated subsidiaries	 	 	—	 	 	 	—	 	 	 	—	 	
Cost of operations	 	 	—	 	 	 	—	 	 	 	—	 	
Interest Expense	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	
Total statement of operations impact before tax	 	$	67	 	 	$	—	 	 	$	67	 	
 	 	
     With the reclassification of Flinders as a discontinued operation, previously designated cash flow hedges were no longer effective beyond the expected date of sale and thus the deferred gain previously recorded in OCI of approximately $11 million was recognized as a derivative gain for the three months ended June 30, 2006, and is included in income from discontinued operations.
     The following table summarizes the pre-tax effects of non-hedge derivatives and derivative activities that do not qualify as hedges on NRG’s statement of operations for the six months ended June 30, 2006:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Energy	 	 	 	 	 	 	 	
(In millions)	 	Commodities	 	 	Interest Rate	 	 	Total	 	
 	 	
Revenue from majority-owned subsidiaries	 	$	117	 	 	$	—	 	 	$	117	 	
Equity in earnings of unconsolidated subsidiaries	 	 	—	 	 	 	—	 	 	 	—	 	
Cost of operations	 	 	—	 	 	 	—	 	 	 	—	 	
Interest expense	 	 	—	 	 	 	3	 	 	 	3	 	
 	 	
Total statement of operations impact before tax	 	$	117	 	 	$	(3	)	 	$	114	 	
 	 	
     With the reclassification of Flinders as a discontinued operation, previously designated cash flow hedges were no longer effective beyond the expected date of sale and thus the deferred gain previously recorded in OCI of approximately $11 million was recognized as a derivative gain for the six months ended June 30, 2006, and is included in income from discontinued operations.
     The following table summarizes the pre-tax effects of non-hedge derivatives and derivative activities that do not qualify as hedges on NRG’s statement of operations for the three months ended June 30, 2005:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Energy	 	 	 	 	 	 	 	
(In millions)	 	Commodities	 	 	Interest Rate	 	 	Total	 	
 	 	
Revenue from majority-owned subsidiaries	 	$	—	 	 	$	—	 	 	$	—	 	
Equity in earnings of unconsolidated subsidiaries	 	 	—	 	 	 	—	 	 	 	—	 	
Cost of operations	 	 	3	 	 	 	—	 	 	 	3	 	
Interest expense	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	
Total statement of operations impact before tax	 	$	(3	)	 	$	—	 	 	$	(3	)	
 	 	
     The following table summarizes the pre-tax effects of non-hedge derivatives and derivative activities that do not qualify as hedges on NRG’s statement of operations for the six months ended June 30, 2005:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Energy	 	 	 	 	 	 	 	
(In millions)	 	Commodities	 	 	Interest Rate	 	 	Total	 	
 	 	
Revenue from majority-owned subsidiaries	 	$	(86	)	 	$	—	 	 	$	(86	)	
Equity in earnings of unconsolidated subsidiaries	 	 	12	 	 	 	—	 	 	 	12	 	
Cost of operations	 	 	1	 	 	 	—	 	 	 	1	 	
Interest expense	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	
Total statement of operations impact before tax	 	$	(75	)	 	$	—	 	 	$	(75	)	
 	 	
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Energy Related Commodities
     As part of NRG’s risk management activities, NRG manages the commodity price risk associated with the Company’s competitive supply activities and the price risk associated with power sales from NRG’s electric generation facilities. In doing so, the Company may enter into a variety of derivative and non-derivative instruments, including the following:
 	•	 	Forward contracts, which commit NRG 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.	
 	 	 	 	
 	•	 	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 the Company’s electric generation operations.	
 	 	 	 	
 	•	 	Fixing the price of a portion of anticipated fuel purchases for the operation of NRG’s power plants.	
 	 	 	 	
 	•	 	Fixing the price of a portion of anticipated energy purchases to supply NRG’s load-serving customers.	
     Ineffectiveness will result from a difference in the relative price movements between a financial transaction and the underlying physical pricing point. If this difference is large enough, it will cause an entity to discontinue the use of hedge accounting. During the three and six months ended June 30, 2006, NRG’s pre-tax earnings were affected by an unrealized gain of $44 million and $36 million, respectively, due to the ineffectiveness associated with financial forward contracted electric sales.
     For the three and six months ended June 30, 2006, NRG’s pre-tax earnings were affected by an unrealized gain of $67 million and $117 million, respectively, associated with changes in the fair value of energy related derivative instruments not accounted for as hedges in accordance with SFAS 133. For the three and six months ended June 30, 2005, NRG’s pre-tax earnings were affected by unrealized losses of $3 million and $75 million, respectively, associated with changes in the fair value of energy-related derivative instruments not accounted for as hedges in accordance with SFAS No. 133.
     For the three and six months ended June 30, 2006, NRG reclassified losses of $20 million and $11 million, from OCI to current period earnings. For the three and six months ended June 30, 2005, NRG reclassified losses of $1 million and gains of $2 million, respectively, from OCI to current period earnings on energy-related derivative instruments accounted for as hedges.
     At June 30, 2006, NRG had hedge and non-hedge energy related commodity contracts extending through December 31, 2026.
Interest Rates
     NRG is exposed to changes in interest rates through the Company’s issuance of variable rate and fixed rate debt. In order to manage this interest rate risk, NRG entered into interest-rate swap agreements. In January 2006, in anticipation of the New Senior Credit Facility, NRG 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 with any gains/(losses) deferred on the balance sheet in OCI. In February 2006, with the completion of the sale of the Senior Notes, the Company designated 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 NRG’s 8% Second Priority Notes which were effectively replaced by the Senior Notes. For the three months ended June 30, 2006, NRG did not recognize any ineffectiveness associated with this hedging relationship. For the six months ended June 30, 2006, NRG recognized $3 million in ineffectiveness associated with this hedging relationship. NRG does not foresee any ineffectiveness of this hedging relationship in the future.
     As of June 30, 2006, all of NRG’s interest rate swap arrangements had been designated as either cash flow or fair value hedges.
     For the three and six months ended June 30, 2006, NRG reclassified $1 million and $3 million, respectively, from OCI to current period earnings and expects to reclassify approximately $2 million of deferred gains to earnings during the next twelve months associated with interest rate swaps accounted for as hedges.
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     At June 30, 2006, NRG had interest rate derivative instruments extending through June 2019.
Foreign Currency Exchange Rates
     To preserve the U.S. dollar value of projected foreign currency cash flows, NRG may hedge, or protect those cash flows if appropriate using available foreign currency hedging instruments. In connection with the sale of Flinders as discussed in Note 3, NRG purchased an option to protect against any negative adverse affects from the exchange rate related to the proceeds from the sale. As of June 30, 2006, the results of any outstanding foreign currency exchange contracts were immaterial to NRG’s financial results.
Note 8 — Long-Term Debt
Cash Tender Offer and Consent Solicitation
     On December 15, 2005, NRG commenced a cash tender offer and consent solicitation for any and all outstanding $1.1 billion aggregate principal amount of the Company’s 8% Second Priority Notes. On that date, NRG 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 8% Second Priority Notes and the Texas Genco Notes was part of NRG’s previously announced financing plan in connection with the acquisition of Texas Genco LLC. As of February 2, 2006, NRG had received valid tenders from holders in aggregate principal amount of the 8% Second Priority Notes, representing approximately 99.96% of the outstanding 8% Second Priority 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 8% Second Priority Notes of approximately $1.2 billion was paid by NRG on February 2, 2006 and included $0.1 billion prepayment penalty which was recorded in debt refinancing expense in the consolidated income statement. The purchase price for the Texas Genco Notes of approximately $1.2 billion was paid by NRG on February 3, 2006 and included $0.1 billion prepayment penalty which was recorded as an acquisition cost for the acquisition of NRG Texas.
New Senior Credit Facility
     On February 2, 2006, NRG also entered into a new senior secured credit facility, or the New Senior 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. The New Senior Credit Facility consisted 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 NRG’s 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 June 30, 2006, NRG had $3.6 billion outstanding under the Company’s Term Loan Facility. As of June 30, 2006, NRG had issued $884 million under the Company’s Letter of Credit Facility and $154 million in letters of credit under the Company’s Revolving Credit Facility.
     On January 31, 2006, NRG used proceeds from the issuance of common stock and cash on hand to repay the $446 million outstanding principal balance of NRG’s senior secured term loan facility, along with accrued but unpaid interest of approximately $2 million, and terminated the facility. On February 2, 2006, NRG used proceeds from the new debt financing to pay accrued but unpaid fees on the Company’s revolving credit facility and funded letter of credit, and terminated those facilities.
     The New Senior Credit Facility is guaranteed by substantially all of NRG’s 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 NRG’s 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 NRG and its subsidiaries, other than certain limited exceptions. These exceptions include assets such as the assets of certain unrestricted subsidiaries, equity interests in certain of the Company’s 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 NRG’s foreign subsidiaries.
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     The New Senior Credit Facility contains customary covenants, which among other things require NRG to meet certain financial tests, including minimum interest coverage ratio and a maximum leverage ratio on a consolidated basis, and limit NRG’s 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.	
     NRG however has the option to prepay the New Senior Credit Facility in whole or in part at any time.
     In anticipation of the New Senior Credit Facility, in January 2006, NRG entered into a series of interest rate swaps. These interest rate swaps became effective on February 15, 2006 and are intended to hedge the risks associated with floating interest rates. For each of the interest rate swaps, the Company pays its counterparty the equivalent of a fixed interest payment on a predetermined notional value, and NRG receives quarterly the equivalent of a floating interest payment based on 3-month LIBOR calculated on the same notional value. All interest rate swap payments by NRG and its 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, NRG 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 called the Senior Notes. The Senior Notes were issued under an Indenture, dated February 2, 2006, or the Indenture, between NRG 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 NRG, 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 NRG, the Guarantors named therein and the Trustee, relating to the 7.375% Senior Notes. On March 14, 2006, NRG 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, NRG executed a Fifth Supplemental Indenture and a Sixth Supplemental Indenture, whereby the WCP 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 June 30, 2006, NRG had $3.6 billion in principal outstanding under the Company’s Senior Notes.
     At any time prior to February 1, 2009, NRG 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, NRG 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% Senior Notes or the First Applicable 7.25% Redemption Date, NRG 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%.
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     The following table sets forth the premium upon redemption for the 7.25% Senior Notes.
 	 	 	 	 	
Redemption Period	 	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% Senior Notes or the First Applicable 7.375% Redemption Date, NRG 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.
 	 	 	 	 	
Redemption Period	 	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 NRG and its 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 NRG’s ability and certain of its 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 NRG and its subsidiaries assets.	
Debt of Discontinued Operations
     As discussed in Note 3, NRG entered into a sale and purchase agreement on June 1, 2006 for the sale of Flinders to Babcock & Brown Power Pty. The sale of Flinders includes the assumption of $174 million (AU$238 million) of non-recourse debt obligations, subject to customary purchase price adjustments.
     On March 29, 2006, NRG 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.
NRG Promissory Note
     On June 5, 2006 NRG repaid the principal and interest at maturity on its outstanding $10 million note payable with Xcel Energy.
Note 9 — Changes in Capital Structure
     As of June 30, 2006, NRG 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.
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5.75% Preferred Stock
     On February 2, 2006, NRG completed the issuance of 2,000,000 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 NRG’s common stock. If the applicable market value of NRG 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 NRG common stock for every share of 5.75% Preferred Stock outstanding. If the applicable market value of NRG 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 NRG common stock for every share of 5.75% Preferred Stock outstanding. If the applicable market value of NRG 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, NRG completed the issuance of 20,855,057 shares of NRG’s 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, NRG issued 35,406,292 shares of common stock to the Sellers. Of this amount, 19,346,788 shares were issued from treasury and 16,059,504 were newly issued shares. See Note 3 for a further discussion.
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 its 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 NRG to grant second priority liens on NRG’s other assets in the United States in order to secure obligations under power sales agreements and related hedges, with certain limitations. 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 July 24, 2006, the net exposure on the hedges that are subject to the second lien structure was $1.6 billion. Net exposure is inclusive of forward mark-to-market, account receivables and payables and collateral outstanding.
     The following table summarizes the utilization of the second lien structure:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Equivalent Net Sales secured by Second Lien Structure (a)	 	2006 (b)	 	2007	 	2008	 	2009	 	2010	 	2011	
 	
In MW	 	 	1,811	 	 	 	3,019	 	 	 	2,573	 	 	 	3,566	 	 	 	2,299	 	 	 	554	 	
As a percentage of net baseload capacity in collateral pool	 	 	62	%	 	 	43	%	 	 	37	%	 	 	51	%	 	 	33	%	 	 	8	%	

(a)	 	Equivalent Net Sales include natural gas swaps converted using a weighted average heat rate by region.	
(b)	 	2006 MW value consists of August through December positions only.	
Note 10 — Equity Compensation
     Incentive Compensation Plans
     In December 2004, the FASB issued a revision to SFAS 123, or SFAS No. 123(R) Share-Based Payment which requires NRG to modify the recognition of expense for stock-based compensation in the statement of income. NRG adopted the requirements of SFAS No. 123(R) effective January 1, 2006 using the modified prospective method. The provisions of SFAS 123(R) did not result in a significant change in NRG’s compensation expense because the Company previously recognized compensation expense in the statements of income under SFAS 123. In accordance with SFAS No. 123(R), NRG estimated a forfeiture rate for each of the Company’s 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 were immaterial to NRG’s results.
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     Long-Term Incentive Plan or LTIP
     As of June 30, 2006, a total of 8,000,000 shares of NRG common stock were available for issuance under the LTIP, subject to adjustments in the event of a reorganization, recapitalization, stock split, reverse stock split, stock dividend, and combination of shares, merger or similar change in NRG’s structure or 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 4,250,421 shares of common stock remaining available for grants under NRG’s LTIP as of June 30, 2006.
     Non-Qualified Stock Options or NQSO’s
     NQSO’s granted under the LTIP 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 NO 123(R) for share options with graded vesting issued after January 1, 2006, NRG recognizes compensation costs 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 NRG’s outstanding NQSO’s, and six years for the remaining 1.1 million NQSO’s. The aggregate intrinsic value for stock options outstanding at June 30, 2006 and 2005 were approximately $25 million and $14 million, respectively. The aggregate intrinsic value for stock options exercisable at June 30, 2006 and 2005 were approximately $15 million and $5 million, respectively. The weighted average remaining contractual term for stock options outstanding at June 30, 2006 and 2005 were approximately six and seven years respectively. The weighted average remaining contractual term for stock options exercisable at June 30, 2006 and 2005 were approximately six and seven years respectively.
     The fair value of stock option grants is 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 six months ended June 30, 2005 and 2006:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Weighted	 	 	Weighted Average	 	
 	 	 	 	 	 	Average	 	 	Grant-Date Fair	 	
(In whole, except weighted average data)	 	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 June 30, 2005	 	 	962,751	 	 	 	23.15	 	 	 	12.15	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Exercisable at June 30, 2005	 	 	313,248	 	 	 	23.01	 	 	 	12.11	 	
 	
Outstanding as of December 31, 2005	 	 	1,095,251	 	 	 	25.04	 	 	 	 	 	
Granted	 	 	706,305	 	 	 	47.50	 	 	 	14.17	 	
Canceled or Expired	 	 	(70,000	)	 	 	34.71	 	 	 	12.07	 	
Exercised	 	 	(9,000	)	 	 	19.90	 	 	 	9.45	 	
 	
Outstanding at June 30, 2006	 	 	1,722,556	 	 	 	33.89	 	 	 	13.08	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Exercisable at June 30, 2006	 	 	607,163	 	 	 	23.22	 	 	 	12.25	 	
 	
     The fair value of NQSO’s issued during the six months ended June 30, 2006 was based on the following assumptions:
 	 	 	 	 	
Six Months Ended June 30,	 	2006	
 	
Weighted –average annualized valuation assumptions	 	 	 	 	
Expected Volatility	 	 	28.10% - 29.64%	 	
Weighted Average Volatility	 	 	28.85	%	
Expected Dividends	 	 	—	 	
Expected Term (in years)	 	 	4 - 6	 	
Risk Free Rate	 	 	4.30%-5.05	%	
Forfeiture Rate	 	 	8	%	
 	 	 	 	 	
     NRG uses an expected term of four years for NQSO’s based on the simple average of the contractual 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.
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     Restricted Stock Units or RSU’s
     RSU’s granted under the LTIP fully vest three years from the date of issuance. To calculate compensation expense, the fair value of the RSU’s is based on the closing price of NRG common stock on the date of grant. Such compensation expenses, net of forfeitures, are amortized over the three-year requisite service period. NRG 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 NRG’s historical forfeitures, employment turnover, and expected future behavior. The aggregate intrinsic value for non-vested RSU’s on June 30, 2006 and June 30, 2005 were approximately $67 million and $32 million, respectively.
     The following table shows the change in the outstanding RSU balance for the six months ended June 30, 2005 and 2006:
 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Weighted	 	
 	 	 	 	 	 	Average Grant-	 	
 	 	 	 	 	 	Date Fair Value	 	
Non-vested Share (In whole except weighted average data)	 	Shares	 	 	Per Share	 	

Non-vested as of December 31, 2004	 	 	880,994	 	 	$	21.59	 	
Granted	 	 	12,750	 	 	 	35.14	 	
Canceled	 	 	(39,500	)	 	 	21.71	 	
 	 	
Non-vested at June 30, 2005	 	 	854,244	 	 	 	20.82	 	

Non-vested as of December 31, 2005	 	 	1,285,944	 	 	 	27.14	 	
Granted	 	 	200,373	 	 	 	47.24	 	
Canceled	 	 	(90,800	)	 	 	28.45	 	
 	 	
Non-vested at June 30, 2006	 	 	1,395,517	 	 	 	29.93	 	
 	 	
     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 NRG 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 June 30, 2006 and June 30, 2005 were approximately $7 million and $5 million respectively. The aggregate intrinsic value for DSU’s converted for the six months ended June 30, 2006 and June 30, 2005 were $0.4 million and $0.2 million respectively. None of the DSU’s issued was canceled or had expired as at June 30, 2006 and 2005.
     The following table shows the change in the outstanding DSU balance for the six months ended June 30, 2005 and 2006:
 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Weighted Average	 	
 	 	 	 	 	 	Grant-Date Fair	 	
(In whole, except weighted average data)	 	Shares	 	 	Value Per Share	 	
 	 	
Outstanding as of December 31, 2004	 	 	60,281	 	 	$	20.31	 	
Granted	 	 	64,851	 	 	 	37.36	 	
Conversions	 	 	(6,298	)	 	 	34.24	 	

Outstanding at June 30, 2005	 	 	118,834	 	 	 	28.88	 	

Outstanding as of December 31, 2005	 	 	122,184	 	 	 	29.21	 	
Granted	 	 	25,830	 	 	 	49.22	 	
Conversions	 	 	(7,594	)	 	 	38.75	 	
 	 	
Outstanding at June 30, 2006	 	 	140,420	 	 	 	32.38	 	
 	 	
     Performance Units or PU’s
     38,600 of NRG’s outstanding PU’s will be paid out on August 1, 2008 if the measurement price, that is the average closing price of NRG’s 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 remaining 172,832 outstanding PU’s will be paid out starting in the first quarter of fiscal year 2009 through the second quarter of fiscal year 2011 if the measurement price is equal to or greater than the following target prices as shown in the table below.
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Grant Date	 	Shares	 	 	Target Price	 	 	Maximum Price	 	
 	
January 3, 2006	 	 	86,400	 	 	$	67.37	 	 	$	79.49	 	
February 3, 2006	 	 	52,632	 	 	$	66.41	 	 	$	77.67	 	
March 1, 2006	 	 	25,000	 	 	$	61.82	 	 	$	72.29	 	
May 31, 2006	 	 	8,800	 	 	$	69.90	 	 	$	81.74	 	

     The fair value of the PU’s was estimated on the date of grant using a Monte Carlo simulation 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 an 8% forfeiture rate, will be amortized over the three-year requisite service period for the majority of the outstanding PU’s. However, a relatively small portion of approximately 4,400 PU’s will be amortized over a five year requisite period.
     The following table shows the change in the outstanding PU balance for the six months ended June 30, 2006.
 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Weighted Average	 	
 	 	 	 	 	 	Grant-Date Fair	 	
Non-vested Shares	 	Shares	 	 	Value Per Share	 	
 	
Non-vested as of December 31, 2005	 	 	44,900	 	 	$	29.87	 	
Granted	 	 	178,732	 	 	 	35.02	 	
Canceled	 	 	(12,200	)	 	 	32.23	 	
 	
Non-vested at June 30, 2006	 	 	211,432	 	 	 	34.09	 	
 	
     The aggregate intrinsic value for PU’s outstanding as of June 30, 2006 was approximately $10 million. There were no PU’s outstanding as of June 30, 2005. Significant assumptions used in the fair value model during the period with respect to PU’s are summarized below:
 	 	 	 	 	
Six months ended June30,	 	2006	
 	
Weighted –average annualized valuation assumptions	 	 	 	 	
Expected Volatility	 	 	28.10% - 29.64%	 	
Weighted Average Volatility	 	 	28.38	%	
Expected Dividends	 	 	—	 	
Expected Term (in years)	 	 	3-5	 	
Risk Free Rate	 	 	4.30%-5.04	%	
Forfeiture Rate	 	 	8	%	
 	
Supplemental information:
     The following table summarizes total compensation expense recognized in accordance with SFAS 123(R) for the six months ended June 30, 2006 and 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 June, 2006:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Total non-vested	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	compensation cost	 	 	Weighted average	 	 	 	
 	 	Compensation expense	 	 	not yet recognized	 	 	life remaining	 	 	 	
 	 	 	 	 	
(In millions, except weighted average data)	 	 	Six months ended June 30	 	As of June 30	 	 	 	
 	
Award	 	2006	 	2005	 	2006	 	2006	 	 	
 	
Stock Options	 	$	2.1	 	 	$	1.8	 	 	$	9.7	 	 	 	1.4	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Deferred Stock Units	 	 	1.3	 	 	 	2.4	 	 	 	—	 	 	 	—	 	 	 	
Restricted Stock Units	 	 	4.3	 	 	 	2.4	 	 	 	22.6	 	 	 	1.4	 	 	 	
Performance Units	 	 	1.0	 	 	 	—	 	 	 	6.0	 	 	 	2.5	 	 	 	
 	 	 	
Total	 	$	8.7	 	 	$	6.6	 	 	$	38.3	 	 	 	 	 	 	 	
 	 	 	
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Note 11 — 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 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 are calculated using the treasury stock method. The dilutive effects of the deferred stock units are included in the denominator for purposes of computing diluted earnings per share under the if-converted method.
     Dilutive effect for other equity instruments — NRG’s 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.
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     The reconciliation of basic earnings per common share to diluted earnings per share is shown in the table below:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Three months ended June 30	 	 	Six months ended June 30	 	
 	 	 	
(In millions, except per share data)	 	2006	 	 	2005	 	 	2006	 	 	2005	 	
 	
Basic earnings per share	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Numerator:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income from continuing operations	 	$	204	 	 	$	23	 	 	$	221	 	 	$	39	 	
Preferred stock dividends	 	 	(14	)	 	 	(4	)	 	 	(25	)	 	 	(8	)	
 	
Net income available to common stockholders from continuing operations	 	 	190	 	 	 	19	 	 	 	196	 	 	 	31	 	
Discontinued operations, net of income tax expense	 	 	(1	)	 	 	1	 	 	 	8	 	 	 	8	 	
 	
Net income available to common stockholders	 	$	189	 	 	$	20	 	 	$	204	 	 	$	39	 	

Denominator:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Weighted average number of common shares outstanding	 	 	137.0	 	 	 	87.0	 	 	 	127.3	 	 	 	87.0	 	
Basic earnings per share:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income from continuing operations	 	$	1.39	 	 	$	0.22	 	 	$	1.55	 	 	$	0.35	 	
Discontinued operations, net of income tax expense	 	 	(0.01	)	 	 	0.01	 	 	 	0.06	 	 	 	0.09	 	
 	
Net income	 	$	1.38	 	 	$	0.23	 	 	$	1.61	 	 	$	0.44	 	
 	
Diluted earnings per share	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Numerator:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income available to common stockholders from continuing operations	 	$	190	 	 	$	19	 	 	$	196	 	 	$	31	 	
Add preferred stock dividends for dilutive preferred stock	 	 	11	 	 	 	—	 	 	 	20	 	 	 	—	 	
 	
Adjusted income from continuing operations	 	 	201	 	 	 	19	 	 	 	216	 	 	 	31	 	
Discontinued operations, net of tax	 	 	(1	)	 	 	1	 	 	 	8	 	 	 	8	 	
 	
Net income available to common stockholders	 	$	200	 	 	$	20	 	 	$	224	 	 	$	39	 	
 	
Denominator:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Weighted average number of common shares outstanding	 	 	137.0	 	 	 	87.0	 	 	 	127.3	 	 	 	87.0	 	
Incremental shares attributable to the issuance of non-vested restricted stock units (treasury stock method)	 	 	0.9	 	 	 	0.4	 	 	 	0.8	 	 	 	0.4	 	
Incremental shares attributable to the assumed conversion of deferred stock units (if-converted method)	 	 	0.1	 	 	 	0.1	 	 	 	0.1	 	 	 	0.1	 	
Incremental shares attributable to the issuance of non-vested non-qualifying stock options (treasury stock method)	 	 	0.5	 	 	 	0.2	 	 	 	0.5	 	 	 	0.2	 	
Incremental shares attributable to the assumed conversion of convertible preferred stock (if-converted method)	 	 	20.8	 	 	 	—	 	 	 	18.9	 	 	 	—	 	
 	
Total dilutive shares	 	 	159.3	 	 	 	87.7	 	 	 	147.6	 	 	 	87.7	 	
Diluted earnings per share:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income from continuing operations	 	$	1.26	 	 	$	0.21	 	 	$	1.47	 	 	$	0.34	 	
Discontinued operations, net of tax	 	 	—	 	 	 	0.01	 	 	 	0.05	 	 	 	0.09	 	
 	
Net income	 	$	1.26	 	 	$	0.22	 	 	$	1.52	 	 	$	0.43	 	
 	
     For the six months ended June 30, 2006, outstanding preferred shares which are convertible on a weighted-average basis, into 18.9 million shares of common stock, were included in the computation. Options to purchase 623,805 shares of common stock were not included in the computation because the effect would have been anti-dilutive.
     For the six months ended June 30, 2005, outstanding preferred shares which are convertible into 10,500,000 shares of common stock were not included in the computation because the effect would have been anti-dilutive.
Note 12 — Segment Reporting
     NRG’s identified reportable segments are primarily based on geographic areas, both domestic and foreign. On February 2, 2006 NRG acquired Texas Genco LLC now referred to as 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 these segments net income for the three and six months ended months ended June 30, 2006, by $20 million and $34 million for the Northeast segment and $9 million and $16 million for the South Central segment, respectively. During the second quarter of 2005, such interest expense was immaterial to both segments.
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 	 	Three months ended June 30, 2006	 	
 	 	Wholesale Power Generation	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	All Other	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	South	 	 	 	 	 	 	Other North	 	 	 	 	 	 	Other	 	 	Alternative	 	 	Non-	 	 	 	 	 	 	 	
(In millions)	 	Texas	 	 	Northeast	 	 	Central	 	 	Western	 	 	America	 	 	Australia	 	 	International	 	 	Energy	 	 	Generation	 	 	Other	 	 	Total	 	
 	
Operations	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues	 	$	909	 	 	$	303	 	 	$	94	 	 	$	49	 	 	$	—	 	 	$	—	 	 	$	44	 	 	$	19	 	 	$	37	 	 	$	(32	)	 	$	1,423	 	
Depreciation and amortization	 	 	131	 	 	 	22	 	 	 	15	 	 	 	1	 	 	 	2	 	 	 	—	 	 	 	—	 	 	 	1	 	 	 	3	 	 	 	3	 	 	 	178	 	
Equity in earnings of unconsolidated affiliates	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1	 	 	 	—	 	 	 	6	 	 	 	1	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	8	 	
Income/(loss) from continuing operations before income taxes	 	 	292	 	 	 	51	 	 	 	(6	)	 	 	8	 	 	 	1	 	 	 	6	 	 	 	16	 	 	 	4	 	 	 	4	 	 	 	(82	)	 	 	294	 	
Net income/(loss) from continuing operations	 	 	256	 	 	 	51	 	 	 	(6	)	 	 	8	 	 	 	1	 	 	 	5	 	 	 	13	 	 	 	4	 	 	 	4	 	 	 	(132	)	 	 	204	 	
Net income from discontinued operations, net of income taxes	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1	 	 	 	(2	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(1	)	
Net income/(loss)	 	$	256	 	 	$	51	 	 	$	(6	)	 	$	8	 	 	$	2	 	 	$	3	 	 	$	13	 	 	$	4	 	 	$	4	 	 	$	(132	)	 	$	203	 	

Total assets	 	$	12,574	 	 	$	1,704	 	 	$	945	 	 	$	185	 	 	$	221	 	 	$	689	 	 	$	813	 	 	$	28	 	 	$	1,234	 	 	$	1,049	 	 	$	19,442	 	

 	 	Three months ended June 30, 2005	 	 	 	 	 	
 	 	Wholesale Power Generation	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	All Other	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	South	 	 	 	 	 	 	Other North	 	 	 	 	 	 	Other	 	 	Alternative	 	 	Non-	 	 	 	 	 	 	 	 	 	 	 	
(In millions)	 	Northeast	 	 	Central	 	 	Western	 	 	America	 	 	Australia	 	 	International	 	 	Energy	 	 	Generation	 	 	Other	 	 	Total	 	 	 	 	 	
 	
Operations	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues	 	$	316	 	 	$	109	 	 	$	—	 	 	$	5	 	 	$	—	 	 	$	39	 	 	$	20	 	 	$	35	 	 	$	(2	)	 	$	522	 	 	 	 	 	
Depreciation and amortization	 	 	18	 	 	 	15	 	 	 	—	 	 	 	1	 	 	 	—	 	 	 	1	 	 	 	2	 	 	 	3	 	 	 	1	 	 	 	41	 	 	 	 	 	
Equity in earnings of unconsolidated affiliates	 	 	—	 	 	 	—	 	 	 	7	 	 	 	1	 	 	 	6	 	 	 	2	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	16	 	 	 	 	 	
Income/(loss) from continuing operations before income taxes	 	 	39	 	 	 	(7	)	 	 	6	 	 	 	(6	)	 	 	6	 	 	 	23	 	 	 	3	 	 	 	3	 	 	 	(36	)	 	 	31	 	 	 	 	 	
Net income/(loss) from continuing operations	 	 	39	 	 	 	(7	)	 	 	6	 	 	 	(7	)	 	 	5	 	 	 	19	 	 	 	3	 	 	 	2	 	 	 	(37	)	 	 	23	 	 	 	 	 	
Net income/(loss) from discontinued operations, net of income taxes	 	 	—	 	 	 	—	 	 	 	—	 	 	 	2	 	 	 	(1	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1	 	 	 	 	 	
Net income/(loss)	 	$	39	 	 	$	(7	)	 	$	6	 	 	$	(5	)	 	$	4	 	 	$	19	 	 	$	3	 	 	$	2	 	 	$	(37	)	 	$	24	 	 	 	 	 	

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 	 	Six months ended June 30, 2006	 	
 	 	Wholesale Power Generation	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	All Other	 	
 	 	 	 	 	 	 	 	 	 	South	 	 	 	 	 	 	Other North	 	 	 	 	 	 	Other	 	 	Alternative	 	 	Non-	 	 	 	 	 	 	 	
(In millions)	 	Texas (a)	 	 	Northeast	 	 	Central	 	 	Western	 	 	America	 	 	Australia	 	 	International	 	 	Energy	 	 	Generation	 	 	Other	 	 	Total	 	
 	 	
Operations	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues	 	$	1,347	 	 	$	695	 	 	$	266	 	 	$	49	 	 	$	1	 	 	$	—	 	 	$	86	 	 	$	34	 	 	$	88	 	 	$	(53	)	 	$	2,513	 	
Depreciation and amortization	 	 	205	 	 	 	44	 	 	 	30	 	 	 	1	 	 	 	4	 	 	 	—	 	 	 	1	 	 	 	2	 	 	 	6	 	 	 	4	 	 	 	297	 	
Equity in earnings/(losses) of unconsolidated affiliates	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(1	)	 	 	2	 	 	 	12	 	 	 	16	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	29	 	
Income/(loss) from continuing operations before income taxes	 	 	285	 	 	 	183	 	 	 	29	 	 	 	4	 	 	 	60	 	 	 	11	 	 	 	40	 	 	 	6	 	 	 	17	 	 	 	(325	)	 	 	310	 	
Net income/(loss) from continuing operations	 	 	274	 	 	 	183	 	 	 	29	 	 	 	6	 	 	 	59	 	 	 	9	 	 	 	30	 	 	 	6	 	 	 	14	 	 	 	(389	)	 	 	221	 	
Net income/(loss) from discontinued operations, net of income taxes	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	9	 	 	 	(1	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	8	 	
Net income/(loss)	 	$	274	 	 	$	183	 	 	$	29	 	 	$	6	 	 	$	68	 	 	$	8	 	 	$	30	 	 	$	6	 	 	$	14	 	 	$	(389	)	 	$	229	 	

 	
(a) For the period February 2, 2006 to June 30, 2006.	

 	 	Six months ended June 30, 2005	 	 	 	 	 	
 	 	Wholesale Power Generation	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	All Other	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	South	 	 	 	 	 	 	Other North	 	 	 	 	 	 	Other	 	 	Alternative	 	 	Non-	 	 	 	 	 	 	 	 	 	 	 	
(In millions)	 	Northeast	 	 	Central	 	 	Western	 	 	America	 	 	Australia	 	 	International	 	 	Energy	 	 	Generation	 	 	Other	 	 	Total	 	 	 	 	 	
 	 	
Operations	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues	 	$	648	 	 	$	226	 	 	$	—	 	 	$	6	 	 	$	—	 	 	$	82	 	 	$	35	 	 	$	76	 	 	$	(3	)	 	$	1,070	 	 	 	 	 	
Depreciation and amortization	 	 	37	 	 	 	30	 	 	 	—	 	 	 	3	 	 	 	—	 	 	 	2	 	 	 	3	 	 	 	6	 	 	 	2	 	 	 	83	 	 	 	 	 	
Equity in earnings of unconsolidated affiliates	 	 	—	 	 	 	—	 	 	 	12	 	 	 	3	 	 	 	12	 	 	 	26	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	53	 	 	 	 	 	
Income/(loss) from continuing operations before income taxes	 	 	72	 	 	 	2	 	 	 	9	 	 	 	(12	)	 	 	12	 	 	 	69	 	 	 	4	 	 	 	8	 	 	 	(111	)	 	 	53	 	 	 	 	 	
Net income/(loss) from continuing operations	 	 	72	 	 	 	2	 	 	 	9	 	 	 	(13	)	 	 	9	 	 	 	61	 	 	 	4	 	 	 	7	 	 	 	(112	)	 	 	39	 	 	 	 	 	
Net income from discontinued operations, net of income taxes	 	 	—	 	 	 	—	 	 	 	—	 	 	 	3	 	 	 	5	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	8	 	 	 	 	 	
Net income/(loss)	 	$	72	 	 	$	2	 	 	$	9	 	 	$	(10	)	 	$	14	 	 	$	61	 	 	$	4	 	 	$	7	 	 	$	(112	)	 	$	47	 	 	 	 	 	

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Note 13 — Income Taxes
     Income tax expense for the three and six months ended June 30, 2006 was $90 million and $89 million, respectively, compared to income tax expense of $8 million and $14 million, respectively, for the corresponding periods in 2005. The income tax expense for the six months ended June 30, 2006 includes domestic tax expense of $76 million and foreign tax expense of $13 million. The income tax expense for the six months ended June 30, 2005 includes domestic tax expense of $3 million and foreign tax expense of $11 million.
     A reconciliation of the U.S. statutory rate to NRG’s effective tax rate from continuing operations for the six months ended June 30, 2006 and 2005 are as follows:
 	 	 	 	 	 	 	 	 	
 	 	Six months ended June 30	 	
(In millions except rate data)	 	2006	 	 	2005	 	
 	 	
Income From Continuing Operations Before Income Taxes	 	$	310	 	 	$	53	 	
Tax at 35%	 	 	108	 	 	 	19	 	
State taxes	 	 	17	 	 	 	(1	)	
Valuation allowance	 	 	3	 	 	 	4	 	
Disputed claims reserve	 	 	(29	)	 	 	—	 	
Foreign operations	 	 	(14	)	 	 	(20	)	
Permanent differences including subpart F income	 	 	4	 	 	 	12	 	
 	 	
Income Tax Expense	 	$	89	 	 	$	14	 	
 	 	
Effective income tax rate	 	 	28.7	%	 	 	26.4	%	
     The effective income tax rate for the six months ended June 30, 2006 and 2005 differs from the U.S. statutory rate of 35% due to a current tax benefit and a property basis difference relating to disbursements from the disputed claims reserve, subpart F income and dividends, and 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 assets — As of June 30, 2006, NRG has a domestic deferred tax asset of $15 million that is not subject to a full valuation allowance due to positive evidence that enables the Company to carryback current tax losses to previous years. For the six months ended June 30, 2006, NRG’s domestic net deferred tax assets decreased by $87 million which resulted in a corresponding reduction to NRG’s domestic valuation allowance. This movement reduced intangibles by $83 million in accordance with SOP 90-7 and reduced NRG’s tax expense by $4 million for the six months ended June 30, 2006. As a result of losses incurred at some of the foreign locations, the Company established approximately $7 million of additional valuation allowances.
     Acquisition of NRG Texas — On a preliminary basis, NRG established a deferred tax asset of $1.575 billion and $1.560 billion of deferred tax liabilities in purchase accounting as a result of the acquisition of NRG Texas, for which a full valuation allowance has been applied.
     NOL carryforwards — As of June 30, 2006, the Company had NOL carryforwards available for federal income tax purposes of $381 million that will expire through 2026. In addition, NRG has cumulative foreign NOL carryforwards of $365 million that do not have an expiration date (including $101 million associated with discontinued operations).
     NRG believes that it is more likely than not that a benefit will not be realized on a substantial portion of its deferred tax assets. This assessment includes consideration of positive and negative evidence, including NRG’s current financial position and results of current operations, projected future taxable income, including projected operating and capital gains, and available tax planning strategies. Therefore, as of June 30, 2006, a valuation allowance of $622 million was recorded against NRG’s net deferred tax assets.
Note 14 — Benefit Plans and Other Postretirement Benefits or OPEB
     Substantially all employees hired prior to December 5, 2003 were eligible to participate in NRG’s defined benefit pension plans. NRG initiated a noncontributory, defined benefit pension plan effective January 1, 2004, with credit for service from December 5, 2003. In addition, NRG provides postretirement health and welfare benefits (health care and death benefits) for certain groups of employees. Generally, these are groups that were acquired in recent years and for whom prior benefits are being continued (at least for a certain period of time or as required by union contracts). Cost sharing provisions vary by acquisition group and terms of any applicable collective bargaining agreements. NRG expects to contribute approximately $58 million to the Company’s pension plans in 2006.
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     As a result of the acquisition of Texas Genco LLC on February 2, 2006, NRG has assumed responsibility for the liabilities and assets of the Texas Genco LLC pension and retiree welfare plans. The Texas Genco LLC pension plan is a noncontributory defined benefit pension plan that provides cash balance benefits based on all years of service to Texas Genco LLC employees who were employed prior to January 1, 2005. In addition, employees who were hired prior to 1999 are also eligible for grandfathered benefits under a final average pay formula. In most cases, the benefits under the grandfathered formula will be frozen as of December 31, 2008.
     The Texas Genco LLC employees are also covered under an unfunded postretirement health and welfare plan. Each year, employees receive a fixed credit of $750 to their account plus interest. Certain grandfathered employees will receive additional credits through 2008. At retirement, the employees may use their accounts to purchase retiree medical and dental benefits from NRG. NRG’s costs are limited to the amounts earned in the employee’s account; all other costs are paid by the participant. The net periodic pension cost relating to the NRG Texas defined benefit plan for the three and six months ended June 30, 2006 were $3 million and $5 million, respectively and $1 million for both periods for its other postretirement benefits plans. These amounts are included in the tables below.
     Components of Net Periodic Benefit Cost
     The components of net pension and postretirement benefit costs are as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Defined Benefit Pension Plans	 	
 	 	Three months ended June 30,	 	 	Six months ended June 30,	 	
 	 	 	 	
(In millions)	 	2006	 	 	2005	 	 	2006	 	 	2005	 	
 	 	
Service cost benefits earned	 	$	5	 	 	$	3	 	 	$	9	 	 	$	6	 	
Interest cost on benefit obligation	 	 	5	 	 	 	1	 	 	 	8	 	 	 	2	 	
Expected return on plan assets	 	 	(2	)	 	 	—	 	 	 	(3	)	 	 	—	 	
 	 	
Net periodic benefit cost	 	$	8	 	 	$	4	 	 	$	14	 	 	$	8	 	

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Other Postretirement Benefits Plans	 	
 	 	Three months ended June 30,	 	 	Six months ended June 30,	 	
 	 	 	 	
(In millions)	 	2006	 	 	2005	 	 	2006	 	 	2005	 	
 	 	
Service cost benefits earned	 	$	—	 	 	$	1	 	 	$	1	 	 	$	1	 	
Interest cost on benefit obligation	 	 	1	 	 	 	—	 	 	 	2	 	 	 	1	 	
 	 	
Net periodic benefit cost	 	$	1	 	 	$	1	 	 	$	3	 	 	$	2	 	
 	 	
Note 15 — Commitments and Contingencies
     Lease Commitments
     As a result of the acquisition of Texas Genco LLC the Company’s operating lease commitments increased significantly. This significant increase was primarily due to the anticipated commencement of leases for 2,695 railcars over the next two years. As of July 20, 2006, approximately 810 of these railcars had been delivered and were under lease for future commitments of approximately $93 million, all relating to NRG Texas.
     Coal, Gas and Transportation Commitments
     As a result of the acquisition of Texas Genco LLC, NRG’s coal, lignite, and gas purchase and transportation commitments have increased significantly. Future minimum payments under these agreements relating to NRG Texas for the following years are as follows:
 	 	 	 	 	
Year	 	(In millions)	 	
 	 	
July 1, 2006 - December 31, 2006	 	$	485	 	
2007	 	 	788	 	
2008	 	 	743	 	
2009	 	 	747	 	
2010	 	 	466	 	
Thereafter	 	 	2,407	 	
 	 	
Total	 	$	5,636	 	
 	 	
     Legal Issues
     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 record 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
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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 material 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 affect the Company’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 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. In December 2002, the district court found that federal jurisdiction was absent and remanded the cases back to state court. On December 8, 2004, the U.S. Court of Appeals for the Ninth Circuit affirmed the district court in most respects. On March 3, 2005, the Ninth Circuit denied a motion for rehearing. 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 U.S. Court of Appeals for the Ninth Circuit. 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.
     On June 28, 2006, Dynegy executed a term sheet agreeing in principle to settle the class action claims in the natural gas anti-trust cases consolidated and pending in state court in San Diego, California. WCP and some of its subsidiaries are named defendants and Dynegy’s settlement would include full releases for these entities. The settlement would resolve 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. The settlement remains subject to final execution, a fairness hearing, and court approval which are expected by the end of calendar year 2006. It would exclude similar cases filed by individual plaintiffs which Dynegy continues to defend vigorously. 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 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.
     On August 2, 2006, the U.S. Court of Appeals for the Ninth Circuit in the case of Public Utilities Commission of the State of California v. FERC, No. 01-71051 upheld in part and reversed in part several FERC orders and remanded the case back to FERC for further proceedings consistent with the decision. The case arose on a petition for review of a series of FERC orders wherein California sought certain refunds for prices paid for power by consumers and businesses. NRG cannot determine the impact of this decision at this time.
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     On May 17, 2006, the U.S. Bankruptcy Court for the Southern District of New York granted NRG’s motion to disallow all pre-bankruptcy claims filed against NRG related to the California energy crisis in 2000 and 2001.
     FERC Proceedings
     There are proceedings in which WCP and WCP subsidiaries are parties, which either is pending before FERC or on appeal from FERC to various U.S. Courts of Appeal. These cases involve, among other things, allegations of physical withholding, a FERC-established price mitigation plan determining maximum rates for wholesale power transactions in certain spot markets, and the enforceability of, and obligations under, various contracts with, among others, the Cal ISO, CDWR, and the State of California. The CDWR claim involves a February 2002 complaint filed by the State of California demanding that FERC abrogate the CDWR contract between the State and subsidiaries of WCP and seeking refunds associated with revenues collected from CDWR by WCP. In 2003, FERC rejected this demand and subsequently denied rehearing. The case was appealed to the U.S. Court of Appeals for the Ninth Circuit where all briefs were filed and oral argument was held December 8, 2004. Dynegy is indemnified by WCP and WCP is responsible for any loss associated with this CDWR litigation unless any such loss is deemed to have resulted from Dynegy’s gross negligence or willful misconduct, in which case any such loss would be shared by the parties equally.
     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.
     New York Public Interest Research Group
     On October 24, 2005, the U.S. Court of Appeals for the Second Circuit issued its opinion in New York Public Interest Research Group or NYPIRG v. Stephen L. Johnson; Administrator; U.S. Environmental Protection Agency.  In 2000, the NYSDEC issued a NOV to the prior owner of the Huntley and Dunkirk stations. After an unsuccessful administrative challenge to the stations’ Title V air quality permits by NYPIRG, it appealed on October 31, 2003. The Second Circuit held that, during the Title V permitting process for the two stations, the 2000 NOV should have been sufficient for the NYSDEC to have made a finding that the stations were out of compliance. Accordingly, the court stated that the EPA should have objected to the Title V permits on that basis and the permits should have included compliance schedules. All petitions for rehearing before the court were denied. On June 3, 2005, the consent decree among NYSDEC, Niagara Mohawk Power Corporation or NiMo and NRG was entered in federal court, settling the substantive issues discussed by the Second Circuit in its decision. NYSDEC is in the process of incorporating the consent decree obligations into the Huntley and Dunkirk Title V permits so as to make them permit conditions, an action NRG believes is supported by the Second Circuit’s decision.
     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 some or all of the disputes in the action. In a companion 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 May 12, 2005, consolidated the appeal with several pending station service disputes involving NiMo. On June 23, 2006, the D.C. Circuit 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. As a result, NRG has reduced its accrual in this matter by approximately $18 million and believes its remaining reserve is adequate.
     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 2006, the parties submitted their respective statements of the case to NRG’s
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appointed arbitrator. CL&P has yet to select its arbitrator so a third panel member, neutral arbitrator, has yet to be selected. NRG believes it is adequately reserved.
     Itiquira Energetica, S.A.
     NRG’s Brazilian project company, Itiquira Energetica S.A. or Itiquira, the owner of a 156 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 Itiquira in September of 2002 and pertains to certain matters arising under the EPC contract between the parties. Itiquira sought Real 140 million and asserted that Inepar breached the contract. Inepar sought Real 39 million and alleged that Itiquira breached the contract. On September 2, 2005, the arbitration panel ruled in favor of Itiquira, 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, Itiquira’s award was increased to approximately Real 227 million (approximately $97 million as of December 31, 2005). Itiquira 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.
     CFTC Trading Litigation
     On July 1, 2004, the Commodities Futures Trading Commission or CFTC, filed a civil complaint against NRG in Minnesota federal district court, alleging false reporting of natural gas trades from August 2001 to May 2002, and seeking an injunction against future violations of the Commodity Exchange Act. In May 2004, the U.S. Bankruptcy Court presiding over NRG’s chapter 11 expunged the CFTC’s proof of claim. On March 15, 2005, NRG’s motion to dismiss was granted by the federal district court. On May 13, 2005, the CFTC filed a notice of appeal with the U.S. Court of Appeals for the Eighth Circuit. Issues on appeal were fully briefed and oral argument occurred on May 15, 2006; no decision has yet been rendered. On August 4, 2006, the Eighth Circuit reversed and remanded the case back to the district court for further action. On November 17, 2004, a bankruptcy court hearing was held on the CFTC’s motion to reinstate its expunged bankruptcy claim, and on NRG’s motion to enforce the provisions of the NRG plan of reorganization, thereby precluding the CFTC from continuing its federal court action. The bankruptcy court has yet to schedule a hearing or rule on the CFTC’s pending motion to reinstate its expunged claim.
     Texas Asbestos Litigation
     Several of NRG’s plants are the subject of lawsuits, primarily commenced in 2001, against numerous defendants by a large number of individuals who claim personal injury due to alleged exposure to asbestos while working at plant sites in Texas. These are premise-based claims as distinguished from product-based claims. The overwhelming majority of these claimants are third party contractors or sub-contractors who participated in the construction, renovation, and/or repair of various industrial plants, including power plants. As of June 30, 2006, there were 3,428 pending claims. During the second quarter of 2006, there was one new claim filed, one claim was settled, and 99 claims were dismissed or otherwise resolved with no payment. For the six months ended June 30, 2006, there was one claim filed, four claims settled, and 189 claims dismissed or otherwise resolved with no payment. The average portion of the settlements for which NRG had financial responsibility during the first two quarters of 2006 was approximately $20,900, a figure skewed by one larger than usual settlement. While ultimate financial responsibility for uninsured losses relating to asbestos claims has been assumed by NRG, CenterPoint Energy has agreed to continue to indemnify such claims to the extent they are covered by insurance maintained by CenterPoint Energy, subject to reimbursement of the costs of such defense from us. To date, costs of settlement and defense have not been material and a portion of the payments in respect of these claims have been offset by insurance recoveries.
     Disputed Claims Reserve
     As part of the NRG 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 July 12, 2006, the reserve held approximately $10 million in cash and approximately 692,000 shares of common stock. NRG believes this is adequate to ensure sufficient funds to satisfy all remaining disputed claims.
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     Bourbonnais Agreements
     On January 31, 2006, NRG finalized a stipulation and settlement agreement with an equipment manufacturer related to turbine purchase agreements entered into in 1999 and 2001. The stipulation fixes the amount and provides for the allowance of the equipment manufacturer’s proof of claim previously filed in NRG’s bankruptcy proceeding. The settlement agreement provides for a $6 million payment by NRG to the equipment manufacturer, and the release of all claims NRG Bourbonnais and NRG have for the return of payments made under the 1999 and 2001 turbine purchase agreements. Under the settlement agreement, NRG received certain equipment valued at $55 million as well as a one year option to purchase new-build equipment for a fixed price. During the first quarter of 2006, NRG recorded approximately $67 million of other income associated with the settlement which resulted from the reversal of accounts payable totaling $35 million resulting from the discharge of the previously recorded liability, and an adjustment to write up the value of the equipment received to its fair value, resulting in income of approximately $32 million.
Note 16 — 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 level and in the regions and in the states in which the Company operates.
     Texas
     As a result of the Acquisition, NRG has become the beneficiary of decommissioning trusts that have been established to provide funding for decontamination and decommissioning of STP in which NRG owns a 44.0% interest. CenterPoint Energy Houston Electric, LLC, or CenterPoint, and American Electric Power, or AEP, collect, through rates or other authorized charges to their electric utility customers, amounts designated for funding NRG’s portion of the decommissioning of the facility. In the event funds from the trusts are inadequate to fund NRG’s ownership portion of the actual decommissioning costs, CenterPoint and AEP or their successors will be required to collect through rates or other authorized charges to customers as contemplated by the Texas Utility Code all additional amounts required to fund NRG’s obligations relating to the decommissioning of the facility. Following the completion of the decommissioning, if surplus funds remain in the decommissioning trust, the excess will be refunded to the ratepayers of CenterPoint, AEP, or their successors. The fair value of the trust assets are reflected as a non-current asset with an associated long-term liability to reflect the future obligation to fund the decommissioning of the facility from the trust assets or to refund or collect additional amounts from the ratepayers or CenterPoint, AEP or their successors.
     In addition to the nuclear decommissioning trusts, NRG has recorded asset retirement obligations and liabilities in accordance with SFAS 143. The assets and liabilities were recorded on the respective acquisition dates based on the estimated future costs of decontamination and decommissioning of NRG’s 44.0% interest in STP. The asset is being amortized over the remaining licensing period for STP and is reflected as a component of property, plant and equipment. ARO Accretion is being recognized with the associated liability.
     As of June 30, 2006 the trust assets had a market value of $326 million. The unamortized portion of the retirement obligation asset was $225 million. The decommission liability was $325 million, and the reserve to fund the decommissioning from the trust assets and payments to or from ratepayers was $226 million. In accordance with SFAS 71, and due to the fact that NRG does not have any economic exposure for these decommissioning responsibilities, changes in the related assets and liabilities are not reflected in the statement of operations. As such, the total carrying value of all assets and all liabilities associated with the decommissioning and the trusts will always be equal.
          New England
On March 7, 2006, a broad group of New England market participants filed a proposed settlement that 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. The FCM established by the settlement will operate an annual descending clock forward capacity auction, by which ISO-NE will obtain the installed capacity requirement of New England, normally three years in advance. In addition to the forward capacity auction, there will be reconfiguration auctions held annually, monthly and seasonally at which capacity obligations can be sold, bought, or exchanged. For the Company’s Connecticut units subject to RMR Agreements, any transition payment will be credited against the monthly availability payment for those units, resulting in no additional revenues for those units. NRG’s other New England generation units are expected to be eligible for the transition payments. The FCM should provide a competitive market price for all of NRG’s capacity, while enhancing opportunities for NRG to competitively repower its New England facilities. On June 16, 2006, FERC issued an order accepting the proposed settlement.
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     FERC accepted revised RMR agreements for the Devon, Middleton and Montville stations on February 1, 2006, establishing them effective January 1, 2006, and providing for the continued operation of the stations as RMR facilities. The Devon RMR Agreement will terminate ninety days after the commencement of the Locational Forward Reserve Market, or LFRM, but no earlier than January 1, 2007. On May 12, 2006, FERC accepted ISO-NE’s Ancillary Service Market Phase II package that includes the LFRM, granting the requested effective date of October 1, 2006, thus triggering the termination of the Devon RMR Agreement effective January 1, 2007.
     On February 15, 2006, NRG reported to FERC and to ISO-NE that for two days in January 2006, after unit 12 at the Devon station had been removed from service for needed maintenance, it was erroneously reported to ISO-NE as available. NRG further reported that when ISO-NE dispatched the Devon units on January 25, 2006, and unit 12 was unable to respond, inaccurate information was provided to ISO-NE. On March 28, 2006, NRG was advised by FERC that it had commenced a preliminary, non-public, informal investigation into the January 25, 2006, ISO-NE dispatch. That same day, FERC also issued to NRG a data request. On April 24, 2006, NRG submitted to FERC an initial response to the data request and made additional submissions during the second quarter of 2006. On June 21, 2006, NRG received a supplemental data request from FERC to which NRG responded on July 14, 2006. NRG continues to investigate the matter and is cooperating with FERC and ISO-NE. The outcome or impact of this investigation cannot be predicted at this time.
     The complaint filed on September 12, 2005 by Richard Blumenthal, Attorney General for the State of Connecticut against ISO-NE seeking to amend the ISO-NE’s Market Rule 1 to require all electric generation facilities not currently operating under an RMR agreement in Connecticut to be placed under cost-of-service rates remains pending. The resolution of that complaint may impact revenues from NRG’s Connecticut Jet Power and Norwalk facilities which are not currently operating pursuant to an RMR agreement.
     New York
     The dispute is continuing 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 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 to FERC to further explain its decision not to utilize TEP to remedy certain 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 been appealed to the D.C. Circuit which has issued a briefing order.
     On April 19, 2006, a settlement in principle was reached with respect to high prices in the NYISO energy market on May 8 and 9, 2000. As a result of the settlement in principle, NRG will retain the amounts refunded to it in 2005 and expects to receive additional non-material amounts. The settlement was filed with FERC on May 25, 2006 and on July 12, 2006 FERC issued an order accepting the proposed settlement.
     On March 15, 2006, NRG received the results from NYISO Market Monitoring Unit’s review of NRG’s Astoria plant’s 2004 Generating Availability Data System reporting. NRG is reviewing this data and working to resolve this matter with the NYISO. This audit may result in the resettlement of NRG’s capacity revenues from the Astoria facility due to a redetermination of the amount of available capacity. NRG is currently in settlement discussions with the NYISO.
Note 17 — Environmental Matters
     The construction and operation of power projects are subject to stringent environmental and safety protection and land use laws and regulation in the U.S. If such laws and regulations become more stringent, or new laws, interpretations or compliance policies apply and NRG’s facilities are not exempt from coverage, the Company could be required to make extensive modifications to further reduce potential environmental impacts. In general, the effect of future laws or regulations is expected to require the addition of pollution control equipment or the imposition of restrictions on the Company’s operations.
     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 the 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.
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     As part of acquiring existing generating assets, NRG has inherited certain environmental liabilities associated with regulatory compliance and site contamination. Often potential compliance implementation plans are changed, delayed or abandoned due to one or more of the following conditions: (a) extended negotiations with regulatory agencies, (b) a delay in promulgating rules critical to dictating the design of expensive control systems, (c) changes in governmental/regulatory personnel, (d) changes in the interpretation and enforcement of existing laws and regulations, (e) changes in governmental priorities or (f) selection of a less expensive compliance option than originally envisioned.
     On December 20, 2005, seven northeastern states entered into a Memorandum of Understanding to create a regional initiative to establish a cap-and-trade greenhouse gas program for electric generators, referred to as the Regional Greenhouse Gas Initiative, or RGGI. Maryland has now announced its intent to join as well. In March 2006, the states participating in RGGI released a draft model rule to be adopted by the states.
     Texas Region
     NRG estimates approximately $73 million of capital expenditures will be incurred for the period 2006 through 2011 for NRG’s Texas facilities, primarily related to installation of particulate, SO 2 , and NO X  controls, as well as studies for installation of BTA under the Phase II 316(b) Rule. NRG currently updates its estimates for environmental capital expenditures annually, and these estimates can be expected to change over time, in some cases materially. In addition to the capital described above, on June 21, 2006 NRG filed an air permit with the Texas Commission on Environmental Quality to allow the uprate of two units at Parish along with investments in scrubbers for those units. This investment is primarily focused on increasing the output of Parish.
     Northeast Region
     NRG maintains financial assurance to cover costs associated with landfill closure, post-closure care and monitoring activities. NRG has funded trusts to provide such financial assurance in the amount of approximately $6 million in New York and approximately $7 million in Delaware. NRG must also maintain financial assurance for closing interim status Resource Conservation and Recovery Act facilities and has funded a trust in the amount of approximately $2 million for this purpose.
     NRG has proposed a remedial action plan to be implemented over the next two to eight years (depending on the station) to address historical ash contamination at facilities in the Northeast region. The total estimated cost is not expected to exceed $1.4 million. Other remedial obligations at the Arthur Kill generating station have been established in discussions between NRG and the NYSDEC and are estimated to be approximately $1 million. Remedial investigations continue at the Astoria generating station with long-term clean-up liability expected to be approximately $3 million. NRG may be required to remediate historical coal tar contamination and/or record a deed restriction on the Astoria property if significant contamination is to remain in place.
     As a result of a small 2001 underground fuel line leak at the Company’s Vienna Generating Station, NRG submitted a plan for remediation to the Maryland Department of the Environment or MDE. The MDE has not formally responded. The remediation in connection with this matter is not expected to exceed $1 million.
     As of December 31, 2005, NRG estimated that the Company will incur total environmental capital expenditures of approximately $367 million for the period 2006 through 2011 for the facilities in New York, Connecticut, Delaware and Massachusetts. These expenditures will be primarily related to installation of particulate, SO 2 , and NO X  controls, as well as installation of BTA under the Phase II 316(b) Rule. NRG currently updates its estimates for environmental capital expenditures annually, and these estimates can be expected to change over time, in some cases materially.
     In January 2006, NRG Indian River Operations, Inc. received a letter of informal notification from Delaware Department of Natural Resources and Environmental Control or DNREC stating that it may be a potentially responsible party with respect to a historic captive landfill. NRG is working with the DNREC, through the Voluntary Clean-up Program to investigate the site. Although the Company is unable to predict the exact impact at this time, NRG believes the cost to remediate will not be material.
     South Central Region
     On January 27, 2004, Louisiana Generating, LLC and Big Cajun II received a request under Section 114 of the CAA from USEPA seeking information primarily related to physical changes made at Big Cajun II and subsequently received a notice of violation, or NOV, based on alleged NSR violations. NRG submitted multiple responses commencing February 27, 2004 and ending on October 20, 2004. On May 9, 2006, these same entities received from the USEPA a notice of deficiency related to their responses. NRG responded on May 22, 2006, and a document review by the USEPA is planned for August 15, 2006.
     Liabilities associated with closure, post-closure care and monitoring of the ash ponds owned and operated on site at the Big Cajun II Generating Station are addressed through the use of a trust fund maintained by NRG in the amount of approximately $5 million. Annual payments are made to the fund in the amount of approximately $0.1 million.
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     As of December 31, 2005, NRG estimated that approximately $252 million of capital expenditures will be incurred during the period 2006 through 2011 for the Company’s South Central facilities, primarily related to installation of particulate, SO 2 , and NO X  controls to comply with the CAIR and Clean Air Mercury rules, as well as studies for installation of BTA under the Phase II 316(b) Rule. NRG currently updates its estimates for environmental capital expenditures annually, and these estimates can be expected to change over time, in some cases materially. Current co-op contracts allow recovery of 93% of costs incurred by complying with new laws, including interest, over the asset life of the required expenditures.
     Western Region
     The Asset Purchase Agreements for the Long Beach, El Segundo, Encina, and San Diego gas turbine generating facilities provide that SCE and San Diego Gas & Electric, or SDG&E, as sellers retain liability, and indemnify NRG, for existing soil and groundwater contamination that exceeds remedial thresholds in place at the time of closing. Having identified existing contamination, SCE and SDG&E agreed to address contamination and are undertaking corrective action at the Encina and San Diego plant sites.
     NRG remediated contamination from a 2002 oil leak at the El Segundo Generating Station. Contaminated soils beneath the foundation were left in place, with approval from the Los Angeles Regional Water Quality Control Board, for removal when the building is demolished.
     As part of decommissioning the 32nd Street Naval Station facility combustion turbine site in San Diego, investigation and remediation of contaminated soils in inaccessible areas may be required in the future. Although the Company is unable to predict the exact impact at this time, NRG believes the cost to remediate will not be material.
     Other North America
     Liabilities of NRG’s Resource Recovery business associated with closure, post-closure care and monitoring of the Company’s Becker refuse derived fuel ash landfill are addressed through the use of a letter of credit maintained by NRG in the amount of approximately $3 million.
Note 18 — Guarantees
     NRG and its subsidiaries enter into various contracts that include indemnification and guarantee provisions as a routine part of the Company’s business activities. Examples of these contracts include asset purchase and sale agreements, commodity sale and purchase agreements, joint venture agreements, operations and maintenance agreements, service agreements, settlement agreements, and other types of contractual agreements with vendors and other third parties. These contracts generally indemnify the counter-party for tax, environmental liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. In many cases, NRG’s maximum potential liability cannot be estimated, since some of the underlying agreements contain no limits on potential liability.
     The descriptions below update, and should be read in conjunction with, the complete descriptions under Note 29 Guarantees and Other Contingent Liabilities in NRG’s Form 10-K for the fiscal year ended December 31, 2005.
     With the acquisition of Texas Genco LLC, NRG assumed several guarantee obligations relating to Texas Genco LLC entities. Under these guarantees, NRG Texas has guaranteed the payment obligations of NRG Texas LP (formerly known as Texas Genco II LP) under commercial agreements to various parties. Maximum obligations under these guarantees as of June 30, 2006 were $38 million. For the six months ended June 30, 2006, NRG increased its guarantee obligations under other commercial arrangements by $107 million. These pertain to payment obligations of NRG Power Marketing Inc., or PMI.
     On July 18, 2006, NRG entered into a guarantee agreement in the amount of $350 million pertaining to payment obligations of PMI, guaranteeing one of the counterparties to the second lien structure. Details to the second lien structure are described in Note 9. While there is no explicitly stated termination date to the second lien structure NRG has the ability to terminate the guarantee with a forty-five day notice.
     On June 1, 2006, NRG, through its wholly-owned entities NRG Caymans C and NRG Caymans P entered into an agreement to sell its investments in Latin America Power entities to a subsidiary of Australia Post. The agreement includes an indemnity from the companies relating to costs incurred by the buyer for breach of representations, warranties or covenants contained in the sales agreement. Liability for these companies is capped at $22.6 million. No claim for a breach of representations or warranties can be brought after March 31, 2007.
     On May 15, 2006, in connection with the sale of NRG’s investment in James River Power LLC, NRG executed a guarantee in favor of Cogentrix of Virginia, Inc. The guarantee stipulates the payment and performance by NRG and its subsidiaries under the terms of the Stock Purchase Agreement dated as of May 9, 2006. NRG’s maximum exposure is limited to $8 million.
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     On May 1, 2006, NRG Ilion Limited Partnership, a subsidiary of NRG, provided an indemnity in connection with the assignment of contracts related to the sale of assets of the company. NRG Ilion’s responsibility is for obligations of NRG Ilion accruing prior to the sale under certain contracts including an Installment Sales Agreement, a license, ground lease and a Payment-in-lieu of Tax or PILOT agreement. NRG does not believe that it will be required to perform under this indemnity.
     On April 13, 2006, in connection with the sale of the Company’s interest in a biomass fuel generation asset located in Cadillac, Michigan, NRG became obligated under an indemnity to the buyer of costs arising from a breach of representations, warranties or covenants contained in the sales agreement. The Company’s maximum exposure is capped at approximately $12 million. NRG does not believe that it will be required to perform under this indemnity.
     On March 10, 2006, NRG executed a guarantee to the benefit of a counterparty under the railcar lease described in Note 15. This guarantee covers payment and performance obligations of the Company’s wholly-owned subsidiary, NRG Texas LP, under the relevant lease documents. NRG does not believe that it will be required to perform under this indemnity.
     On March 28, 2006, NRG executed a guarantee to the benefit of AmerenUE, the purchaser of the Audrain generating assets. Pursuant to this agreement, NRG guarantees the payment and performance of the Company and its subsidiaries’ obligations pursuant to the sale agreement. This guarantee extends to certain claims made within five years of the sale and the Company’s maximum exposure under this guarantee is $10 million. In addition to this guarantee, NRG received a $2.75 million payment from the project lenders in consideration for retaining certain pre-closing tax liabilities related to the Audrain project. This payment was recorded within other non-current liabilities on the consolidated balance sheet. In consideration for this payment, NRG agreed to indemnify the project lenders, subject to a $10 million cap, for liabilities related to the pre-closing taxes applicable to the Audrain project.
     On March 31, 2006, NRG purchased the remaining 50% interest in WCP from Dynegy. In conjunction with the purchase, NRG agreed to indemnify Dynegy, subject to certain caps and limitations, for breach of representations, warranties, covenants, and losses incurred under the CDWR litigation and certain California electricity-related litigation. For further information about the litigation, see Note 15.
     Because many of the guarantees and indemnities NRG issues to third parties do not limit the amount or duration of the Company’s obligations to perform under them, there exists a risk that NRG may have obligations in excess of the amounts described above. For those guarantees and indemnities that do not limit NRG’s liability exposure, NRG may not be able to estimate what the Company’s liability would be until a claim is made for payment or performance, due to the contingent nature of these contracts.
Note 19 — Condensed Consolidating Financial Information
     As of June 30, 2006, the Company had $1.2 billion of 7.25% Senior Notes and $2.4 billion of 7.375% Senior Notes outstanding. These notes are guaranteed by each of NRG’s current and future wholly-owned domestic subsidiaries, or guarantor subsidiaries. Each of the following guarantor subsidiaries fully and unconditionally guaranteed the Notes as of June 30, 2006.
 	 	 	
Arthur Kill Power LLC	 	NRG California Peaker Operations LLC	
Astoria Gas Turbine Power LLC	 	NRG Texas LLC	
Berrians I Gas Turbine Power LLC	 	NRG Texas LP	
Big Cajun II Unit 4 LLC	 	NRG Connecticut Affiliate Services Inc.	
Cabrillo Power I LLC	 	NRG Devon Operations Inc.	
Cabrillo Power II LLC	 	NRG Dunkirk Operations Inc.	
Chickahominy River Energy Corp.	 	NRG El Segundo Operations Inc.	
Commonwealth Atlantic Power LLC	 	NRG Huntley Operations Inc.	
Conemaugh Power LLC	 	NRG International LLC	
Connecticut Jet Power LLC	 	NRG Kaufman LLC	
Devon Power LLC	 	NRG Mesquite LLC	
Dunkirk Power LLC	 	NRG Mid-Atlantic Affiliate Services Inc.	
Eastern Sierra Energy Company	 	NRG Middletown Operations Inc.	
El Segundo Power LLC	 	NRG Montville Operations Inc.	
El Segundo Power II LLC	 	NRG New Jersey Energy Sales LLC	
GCP Funding Company, LLC	 	NRG New Roads Holdings LLC	
Hanover Energy Company	 	NRG North Central Operations Inc.	
Huntley Power LLC	 	NRG Northeast Affiliate Services Inc.	
Indian River Operations Inc.	 	NRG Norwalk Harbor Operations Inc.	
Indian River Power LLC	 	NRG Operating Services, Inc.	
James River Power LLC	 	NRG Oswego Harbor Power Operations Inc.	
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Kaufman Cogen LP	 	NRG Power Marketing Inc	
Keystone Power LLC	 	NRG Rocky Road LLC	
Long Beach Generation LLC	 	NRG Saguaro Operations Inc.	
Louisiana Generating LLC	 	NRG South Central Affiliate Services Inc.	
Middletown Power LLC	 	NRG South Central Generating LLC	
Montville Power LLC	 	NRG South Central Operations Inc.	
NEO California Power LLC	 	NRG South Texas LP	
NEO Chester-Gen LLC	 	NRG West Coast LLC	
NEO Corporation	 	NRG Western Affiliate Services Inc.	
NEO Freehold-Gen LLC	 	Oswego Harbor Power LLC	
NEO Landfill Gas Holdings Inc.	 	Saguaro Power LLC	
NEO Power Services Inc.	 	Somerset Operations Inc.	
New Genco GP, LLC	 	Somerset Power LLC	
New Genco LP, LLC	 	Texas Genco Financing Corp.	
Norwalk Power LLC	 	Texas Genco GP, LLC	
NRG Affiliate Services Inc.	 	Texas Genco Holdings, Inc.	
NRG Arthur Kill Operations Inc.	 	Texas Genco LP, LLC	
NRG Asia-Pacific, Ltd.	 	Texas Genco Operating Services LLC	
NRG Astoria Gas Turbine Operations, Inc.	 	Texas Genco Services, LP	
NRG Bayou Cove LLC	 	Vienna Operations Inc.	
NRG Generation Holdings, Inc.	 	Vienna Power LLC	
NRG Cabrillo Power Operations Inc.	 	WCP (Generation) Holdings LLC	
NRG Cadillac Operations Inc.	 	West Coast Power 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 its 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.
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NRG Energy, Inc. and Subsidiaries
Condensed Consolidating Statements of Operations
For the Three Months Ended June 30, 2006
(Unaudited)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantor	 	 	Non-Guarantor	 	 	 	 	 	 	 	 	 	 	Consolidated	 	
(In millions)	 	Subsidiaries	 	 	Subsidiaries	 	 	NRG Energy, Inc.	 	 	Eliminations (a)	 	 	Balance	 	
 	 	
Operating Revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues from majority-owned operations	 	$	1,326	 	 	$	83	 	 	$	14	 	 	$	—	 	 	$	1,423	 	
 	 	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cost of majority-owned operations	 	 	676	 	 	 	57	 	 	 	13	 	 	 	—	 	 	 	746	 	
Depreciation and amortization	 	 	168	 	 	 	7	 	 	 	3	 	 	 	—	 	 	 	178	 	
General, administrative and development	 	 	24	 	 	 	5	 	 	 	54	 	 	 	—	 	 	 	83	 	
 	 	
Total operating costs and expenses	 	 	868	 	 	 	69	 	 	 	70	 	 	 	—	 	 	 	1,007	 	
 	 	
Operating Income/(Loss)	 	 	458	 	 	 	14	 	 	 	(56	)	 	 	—	 	 	 	416	 	
 	 	
Other Income/(Expense)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Equity in earnings of consolidated subsidiaries	 	 	14	 	 	 	—	 	 	 	270	 	 	 	(284	)	 	 	—	 	
Equity in earnings of unconsolidated affiliates	 	 	1	 	 	 	7	 	 	 	—	 	 	 	—	 	 	 	8	 	
Write downs and gains/(losses) on sales of equity method investments	 	 	—	 	 	 	14	 	 	 	—	 	 	 	—	 	 	 	14	 	
Other income, net	 	 	23	 	 	 	1	 	 	 	(17	)	 	 	1	 	 	 	8	 	
Interest expense	 	 	(83	)	 	 	(10	)	 	 	(58	)	 	 	(1	)	 	 	(152	)	
 	 	
Total other income/(expense)	 	 	(45	)	 	 	12	 	 	 	195	 	 	 	(284	)	 	 	(122	)	
 	 	
Income From Continuing Operations Before Income Taxes	 	 	413	 	 	 	26	 	 	 	139	 	 	 	(284	)	 	 	294	 	
Income Tax expense/(benefit)	 	 	156	 	 	 	(1	)	 	 	(65	)	 	 	—	 	 	 	90	 	
 	 	
Income From Continuing Operations	 	 	257	 	 	 	27	 	 	 	204	 	 	 	(284	)	 	 	204	 	
Income/(losses) on discontinued operations, net of income tax expense (benefit)	 	 	—	 	 	 	—	 	 	 	(1	)	 	 	—	 	 	 	(1	)	
 	 	
Net Income	 	$	257	 	 	$	27	 	 	$	203	 	 	$	(284	)	 	$	203	 	

(a)	 	All significant intercompany transactions have been eliminated in consolidation.	
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NRG Energy, Inc. and Subsidiaries
Condensed Consolidating Statements of Operations
For the Six Months Ended June 30, 2006
(Unaudited)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantor	 	 	Non-Guarantor	 	 	 	 	 	 	 	 	 	 	Consolidated	 	
(In millions)	 	Subsidiaries	 	 	Subsidiaries	 	 	NRG Energy, Inc.	 	 	Eliminations (a)	 	 	Balance	 	
 	 	
Operating Revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues from majority-owned operations	 	$	2,315	 	 	$	171	 	 	$	27	 	 	$	—	 	 	$	2,513	 	
 	 	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cost of majority-owned operations	 	 	1,304	 	 	 	120	 	 	 	23	 	 	 	—	 	 	 	1,447	 	
Depreciation and amortization	 	 	279	 	 	 	13	 	 	 	5	 	 	 	—	 	 	 	297	 	
General, administrative and development	 	 	46	 	 	 	8	 	 	 	89	 	 	 	—	 	 	 	143	 	
 	 	
Total operating costs and expenses	 	 	1,629	 	 	 	141	 	 	 	117	 	 	 	—	 	 	 	1,887	 	
 	 	
Operating Income/(Loss)	 	 	686	 	 	 	30	 	 	 	(90	)	 	 	—	 	 	 	626	 	
 	 	
Other Income/(Expense)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Equity in earnings of consolidated subsidiaries	 	 	36	 	 	 	—	 	 	 	431	 	 	 	(467	)	 	 	—	 	
Equity in earnings of unconsolidated affiliates	 	 	1	 	 	 	28	 	 	 	—	 	 	 	—	 	 	 	29	 	
Write downs and gains/(losses) on sales of equity method investments	 	 	(3	)	 	 	14	 	 	 	—	 	 	 	—	 	 	 	11	 	
Other income, net	 	 	26	 	 	 	76	 	 	 	(10	)	 	 	(4	)	 	 	88	 	
Refinancing expense	 	 	—	 	 	 	—	 	 	 	(178	)	 	 	—	 	 	 	(178	)	
Interest expense	 	 	(137	)	 	 	(25	)	 	 	(108	)	 	 	4	 	 	 	(266	)	
 	 	
Total other income/(expense)	 	 	(77	)	 	 	93	 	 	 	135	 	 	 	(467	)	 	 	(316	)	
 	 	
Income From Continuing Operations Before Income Taxes	 	 	609	 	 	 	123	 	 	 	45	 	 	 	(467	)	 	 	310	 	
Income Tax expense/(benefit)	 	 	241	 	 	 	34	 	 	 	(186	)	 	 	—	 	 	 	89	 	
 	 	
Income From Continuing Operations	 	 	368	 	 	 	89	 	 	 	231	 	 	 	(467	)	 	 	221	 	
Income/(losses) on discontinued operations, net of income tax expense/(benefit)	 	 	—	 	 	 	10	 	 	 	(2	)	 	 	—	 	 	 	8	 	
 	 	
Net Income	 	$	368	 	 	$	99	 	 	$	229	 	 	$	(467	)	 	$	229	 	

(a)	 	All significant intercompany transactions have been eliminated in consolidation.	
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NRG Energy, Inc. and Subsidiaries
Condensed Consolidating Balance Sheet
June 30, 2006
(Unaudited)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantor	 	 	Non-Guarantor	 	 	 	 	 	 	 	 	 	 	Consolidated	 	
(In millions)	 	Subsidiaries	 	 	Subsidiaries	 	 	NRG Energy Inc.	 	 	Eliminations(a)	 	 	Balance	 	
 	 	
ASSETS	
Current Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	34	 	 	$	130	 	 	$	793	 	 	$	—	 	 	$	957	 	
Restricted cash	 	 	3	 	 	 	55	 	 	 	—	 	 	 	—	 	 	 	58	 	
Accounts receivable-trade, net	 	 	426	 	 	 	38	 	 	 	9	 	 	 	—	 	 	 	473	 	
Inventory	 	 	388	 	 	 	12	 	 	 	2	 	 	 	—	 	 	 	402	 	
Derivative instruments valuation	 	 	528	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	528	 	
Collateral on deposit in support of energy risk management activities	 	 	209	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	209	 	
Prepayments and other current assets	 	 	67	 	 	 	38	 	 	 	696	 	 	 	(614	)	 	 	187	 	
Current assets – discontinued operations	 	 	—	 	 	 	96	 	 	 	—	 	 	 	—	 	 	 	96	 	
 	 	
Total current assets	 	 	1,655	 	 	 	369	 	 	 	1,500	 	 	 	(614	)	 	 	2,910	 	
 	 	
Net property, plant and equipment	 	 	11,377	 	 	 	410	 	 	 	28	 	 	 	—	 	 	 	11,815	 	
 	 	
Other Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Investment in subsidiaries	 	 	617	 	 	 	—	 	 	 	9,125	 	 	 	(9,742	)	 	 	—	 	
Equity investments in affiliates	 	 	29	 	 	 	278	 	 	 	—	 	 	 	—	 	 	 	307	 	
Notes receivable, less current portion	 	 	990	 	 	 	479	 	 	 	4,716	 	 	 	(5,705	)	 	 	480	 	
Goodwill	 	 	1,462	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1,462	 	
Intangible assets, net	 	 	1,171	 	 	 	11	 	 	 	—	 	 	 	—	 	 	 	1,182	 	
Nuclear decommissioning trust fund	 	 	326	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	326	 	
Derivative instruments valuation	 	 	128	 	 	 	4	 	 	 	59	 	 	 	—	 	 	 	191	 	
Deferred income taxes	 	 	15	 	 	 	27	 	 	 	—	 	 	 	—	 	 	 	42	 	
Other non-current assets	 	 	125	 	 	 	58	 	 	 	59	 	 	 	—	 	 	 	242	 	
Intangible assets held-for-sale	 	 	66	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	66	 	
Non-current assets – discontinued operations	 	 	—	 	 	 	419	 	 	 	—	 	 	 	—	 	 	 	419	 	
 	 	
Total other assets	 	 	4,929	 	 	 	1,276	 	 	 	13,959	 	 	 	(15,447	)	 	 	4,717	 	
 	 	
Total Assets	 	$	17,961	 	 	$	2,055	 	 	$	15,487	 	 	$	(16,061	)	 	$	19,442	 	

LIABILITIES AND STOCKHOLDERS’ EQUITY	
Current Liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current portion of long-term debt and capital leases	 	$	461	 	 	$	96	 	 	$	35	 	 	$	(467	)	 	$	125	 	
Accounts payable	 	 	(579	)	 	 	(162	)	 	 	1,081	 	 	 	—	 	 	 	340	 	
Derivative instruments valuation	 	 	640	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	640	 	
Accrued expenses and other current liabilities	 	 	354	 	 	 	55	 	 	 	205	 	 	 	(147	)	 	 	467	 	
Current liabilities – discontinued operations	 	 	—	 	 	 	58	 	 	 	—	 	 	 	—	 	 	 	58	 	
 	 	
Total current liabilities	 	 	876	 	 	 	47	 	 	 	1,321	 	 	 	(614	)	 	 	1,630	 	
Other Liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term debt and capital leases	 	 	4,716	 	 	 	607	 	 	 	8,013	 	 	 	(5,705	)	 	 	7,631	 	
Nuclear decommissioning reserve	 	 	226	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	226	 	
Nuclear decommissioning trust liability	 	 	325	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	325	 	
Deferred income taxes	 	 	—	 	 	 	152	 	 	 	—	 	 	 	—	 	 	 	152	 	
Derivative instruments valuation	 	 	363	 	 	 	1	 	 	 	34	 	 	 	—	 	 	 	398	 	
Out-of-market contracts	 	 	2,320	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	2,320	 	
Other non-current liabilities	 	 	334	 	 	 	28	 	 	 	16	 	 	 	—	 	 	 	378	 	
Non-current liabilities – discontinued operations	 	 	—	 	 	 	278	 	 	 	—	 	 	 	—	 	 	 	278	 	
 	 	
Total non-current liabilities	 	 	8,284	 	 	 	1,066	 	 	 	8,063	 	 	 	(5,705	)	 	 	11,708	 	
 	 	
Total liabilities	 	 	9,160	 	 	 	1,113	 	 	 	9,384	 	 	 	(6,319	)	 	 	13,338	 	
 	 	
Minority interest	 	 	—	 	 	 	1	 	 	 	—	 	 	 	—	 	 	 	1	 	
3.625% Preferred Stock	 	 	—	 	 	 	—	 	 	 	246	 	 	 	—	 	 	 	246	 	
Stockholders’ Equity	 	 	8,801	 	 	 	941	 	 	 	5,857	 	 	 	(9,742	)	 	 	5,857	 	
 	 	
Total Liabilities and Stockholders’ Equity	 	$	17,961	 	 	$	2,055	 	 	$	15,487	 	 	$	(16,061	)	 	$	19,442	 	

(a)	 	All significant intercompany transactions have been eliminated in consolidation.	
42

Table of Contents
NRG Energy, Inc. and Subsidiaries
Condensed Consolidating Statements of Cash Flows
For the Six Months Ended June 30, 2006
(Unaudited)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantor	 	 	Non-Guarantor	 	 	 	 	 	 	 	 	 	 	Consolidated	 	
(In millions)	 	Subsidiaries	 	 	Subsidiaries	 	 	NRG Energy, Inc.	 	 	Eliminations (a)	 	 	Balance	 	
Cash Flows from Operating Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income	 	$	368	 	 	$	99	 	 	$	229	 	 	$	(467	)	 	$	229	 	
Adjustments to reconcile net income to net cash provided (used) by operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Distributions in excess of (less than) equity in earnings of unconsolidated affiliates and consolidated subsidiaries	 	 	(37	)	 	 	(12	)	 	 	(431	)	 	 	467	 	 	 	(13	)	
Depreciation and amortization	 	 	279	 	 	 	24	 	 	 	5	 	 	 	—	 	 	 	308	 	
Amortization of financing costs and debt premium	 	 	—	 	 	 	—	 	 	 	16	 	 	 	—	 	 	 	16	 	
Amortization of power contracts and emission allowances	 	 	(206	)	 	 	(5	)	 	 	—	 	 	 	—	 	 	 	(211	)	
Amortization of unearned equity compensation	 	 	—	 	 	 	—	 	 	 	9	 	 	 	—	 	 	 	9	 	
Write-off of deferred financing costs and debt premium	 	 	—	 	 	 	—	 	 	 	47	 	 	 	—	 	 	 	47	 	
Write down and gains/(losses) of equity method investments	 	 	2	 	 	 	(13	)	 	 	—	 	 	 	—	 	 	 	(11	)	
Deferred income taxes	 	 	46	 	 	 	(1	)	 	 	51	 	 	 	—	 	 	 	96	 	
Nuclear decommissioning liability	 	 	3	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	3	 	
Loss on sale of equipment	 	 	3	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	3	 	
Unrealized (gains)/losses on derivatives	 	 	(49	)	 	 	(11	)	 	 	(54	)	 	 	—	 	 	 	(114	)	
Gain on legal settlement	 	 	—	 	 	 	(67	)	 	 	—	 	 	 	—	 	 	 	(67	)	
Gain on sale of discontinued operations	 	 	—	 	 	 	(10	)	 	 	—	 	 	 	—	 	 	 	(10	)	
Gain on sale of emission allowance	 	 	(67	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(67	)	
Collateral deposit payments in support of energy risk management activities	 	 	272	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	272	 	
Cash used by changes in working capital, net of acquisition and disposition affects	 	 	(212	)	 	 	27	 	 	 	299	 	 	 	—	 	 	 	114	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Cash Provided/(used) by Operating Activities	 	 	402	 	 	 	31	 	 	 	171	 	 	 	—	 	 	 	604	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flows from Investing Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Acquisition of Texas Genco LLC and WCP	 	 	—	 	 	 	—	 	 	 	(4,328	)	 	 	—	 	 	 	(4,328	)	
Decrease/(increase) in restricted cash	 	 	—	 	 	 	(9	)	 	 	—	 	 	 	—	 	 	 	(9	)	
Decrease/(increase) in notes receivable	 	 	(914	)	 	 	14	 	 	 	(3,318	)	 	 	4,232	 	 	 	14	 	
Investments in nuclear decommissioning trust fund securities	 	 	(106	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(106	)	
Purchases of emission allowances	 	 	(78	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(78	)	
Sales of emission allowances	 	 	84	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	84	 	
Proceeds from sale of equipment	 	 	—	 	 	 	1	 	 	 	—	 	 	 	—	 	 	 	1	 	
Proceeds from sale of investments	 	 	63	 	 	 	23	 	 	 	—	 	 	 	—	 	 	 	86	 	
Proceeds from sale of discontinued operations	 	 	—	 	 	 	15	 	 	 	—	 	 	 	—	 	 	 	15	 	
Proceeds from sales of nuclear decommissioning trust fund securities	 	 	103	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	103	 	
Capital expenditures	 	 	(59	)	 	 	(13	)	 	 	(2	)	 	 	—	 	 	 	(74	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Cash Provided/(used) by Investing Activities	 	 	(907	)	 	 	31	 	 	 	(7,648	)	 	 	4,232	 	 	 	(4,292	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flows from Financing Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Payments for dividends	 	 	—	 	 	 	—	 	 	 	(23	)	 	 	—	 	 	 	(23	)	
Funded letter of credit	 	 	—	 	 	 	—	 	 	 	350	 	 	 	—	 	 	 	350	 	
Proceeds from Intercompany Loans	 	 	3,318	 	 	 	—	 	 	 	914	 	 	 	(4,232	)	 	 	—	 	
Proceeds from issuance of common stock	 	 	—	 	 	 	—	 	 	 	986	 	 	 	—	 	 	 	986	 	
Proceeds from issuance of long-term debt	 	 	—	 	 	 	—	 	 	 	7,175	 	 	 	—	 	 	 	7,175	 	
Proceeds for preferred share issuance	 	 	—	 	 	 	—	 	 	 	486	 	 	 	—	 	 	 	486	 	
Deferred debt issuance costs	 	 	—	 	 	 	—	 	 	 	(164	)	 	 	—	 	 	 	(164	)	
Principal payments on short and long-term debt	 	 	(2,772	)	 	 	(14	)	 	 	(1,876	)	 	 	—	 	 	 	(4,662	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Cash Used by Financing Activities	 	 	546	 	 	 	(14	)	 	 	7,848	 	 	 	(4,232	)	 	 	4,148	 	
Effect of Exchange Rate Changes on Cash and Cash Equivalents	 	 	—	 	 	 	3	 	 	 	—	 	 	 	—	 	 	 	3	 	
Change in Cash from Discontinued Operations	 	 	—	 	 	 	1	 	 	 	—	 	 	 	—	 	 	 	1	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Increase (Decrease) in Cash and Cash Equivalents	 	 	41	 	 	 	52	 	 	 	371	 	 	 	—	 	 	 	464	 	
Cash and Cash Equivalents at Beginning of Period	 	 	(7	)	 	 	78	 	 	 	422	 	 	 	—	 	 	 	493	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash and Cash Equivalents at End of Period	 	$	34	 	 	$	130	 	 	$	793	 	 	$	—	 	 	$	957	 	

(a)	 	All significant intercompany transactions have been eliminated in consolidation.	
43

Table of Contents
NRG Energy, Inc. and Subsidiaries
Condensed Consolidating Statements of Operations
For the Three Months Ended June 30, 2005
(Unaudited)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantor	 	 	Non-Guarantor	 	 	 	 	 	 	 	 	 	 	Consolidated	 	
(In millions)	 	Subsidiaries	 	 	Subsidiaries	 	 	NRG Energy, Inc.	 	 	Eliminations (a)	 	 	Balance	 	
Operating Revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues from majority-owned operations	 	$	428	 	 	$	80	 	 	$	15	 	 	$	(1	)	 	$	522	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cost of majority-owned operations	 	 	324	 	 	 	55	 	 	 	9	 	 	 	(1	)	 	 	387	 	
Depreciation and amortization	 	 	33	 	 	 	5	 	 	 	3	 	 	 	—	 	 	 	41	 	
General, administrative and development	 	 	12	 	 	 	5	 	 	 	33	 	 	 	—	 	 	 	50	 	
Corporate relocation charges	 	 	—	 	 	 	—	 	 	 	1	 	 	 	—	 	 	 	1	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total operating costs and expenses	 	 	369	 	 	 	65	 	 	 	46	 	 	 	(1	)	 	 	479	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Income/(Loss)	 	 	59	 	 	 	15	 	 	 	(31	)	 	 	—	 	 	 	43	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Income (Expense)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Equity in earnings of consolidated subsidiaries	 	 	23	 	 	 	—	 	 	 	74	 	 	 	(97	)	 	 	—	 	
Equity in earnings of unconsolidated affiliates	 	 	9	 	 	 	7	 	 	 	—	 	 	 	—	 	 	 	16	 	
Write downs and gains/(losses) on sales of equity method investments	 	 	—	 	 	 	12	 	 	 	—	 	 	 	—	 	 	 	12	 	
Other income, net	 	 	2	 	 	 	11	 	 	 	3	 	 	 	(10	)	 	 	6	 	
Interest expense	 	 	—	 	 	 	(20	)	 	 	(36	)	 	 	10	 	 	 	(46	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total other income/(expense)	 	 	34	 	 	 	10	 	 	 	41	 	 	 	(97	)	 	 	(12	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income From Continuing Operations Before Income Taxes	 	 	93	 	 	 	25	 	 	 	10	 	 	 	(97	)	 	 	31	 	
Income Tax Expense/(Benefit)	 	 	24	 	 	 	(1	)	 	 	(15	)	 	 	—	 	 	 	8	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income From Continuing Operations	 	 	69	 	 	 	26	 	 	 	25	 	 	 	(97	)	 	 	23	 	
Income/(losses) on Discontinued Operations, net of Income Taxes	 	 	—	 	 	 	2	 	 	 	(1	)	 	 	—	 	 	 	1	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Income	 	$	69	 	 	$	28	 	 	$	24	 	 	$	(97	)	 	$	24	 	

(a)	 	All significant intercompany transactions have been eliminated in consolidation.	
44

Table of Contents
NRG Energy, Inc. and Subsidiaries
Condensed Consolidating Statements of Operations
For the Six Months Ended June 30, 2005
(Unaudited)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantor	 	 	Non-Guarantor	 	 	 	 	 	 	 	 	 	 	Consolidated	 	
(In millions)	 	Subsidiaries	 	 	Subsidiaries	 	 	NRG Energy, Inc.	 	 	Eliminations (a)	 	 	Balance	 	
Operating Revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues from majority-owned operations	 	$	880	 	 	$	165	 	 	$	28	 	 	$	(3	)	 	$	1,070	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cost of majority-owned operations	 	 	663	 	 	 	118	 	 	 	18	 	 	 	(3	)	 	 	796	 	
Depreciation and amortization	 	 	66	 	 	 	12	 	 	 	5	 	 	 	—	 	 	 	83	 	
General, administrative and development	 	 	23	 	 	 	12	 	 	 	62	 	 	 	—	 	 	 	97	 	
Corporate relocation charges	 	 	—	 	 	 	—	 	 	 	4	 	 	 	—	 	 	 	4	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total operating costs and expenses	 	 	752	 	 	 	142	 	 	 	89	 	 	 	(3	)	 	 	980	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Income/(Loss)	 	 	128	 	 	 	23	 	 	 	(61	)	 	 	—	 	 	 	90	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Income (Expense)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Equity in earnings of consolidated subsidiaries	 	 	69	 	 	 	—	 	 	 	153	 	 	 	(222	)	 	 	—	 	
Equity in earnings of unconsolidated affiliates	 	 	16	 	 	 	37	 	 	 	—	 	 	 	—	 	 	 	53	 	
Write downs and gains/(losses) on sales of equity method investments	 	 	—	 	 	 	12	 	 	 	—	 	 	 	—	 	 	 	12	 	
Other income, net	 	 	3	 	 	 	32	 	 	 	6	 	 	 	(10	)	 	 	31	 	
Refinancing expense	 	 	—	 	 	 	—	 	 	 	(35	)	 	 	—	 	 	 	(35	)	
Interest expense	 	 	—	 	 	 	(32	)	 	 	(76	)	 	 	10	 	 	 	(98	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total other income (expense)	 	 	88	 	 	 	49	 	 	 	48	 	 	 	(222	)	 	 	(37	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income From Continuing Operations Before Income Taxes	 	 	216	 	 	 	72	 	 	 	(13	)	 	 	(222	)	 	 	53	 	
Income Tax expense/(benefit)	 	 	70	 	 	 	7	 	 	 	(63	)	 	 	—	 	 	 	14	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income From Continuing Operations	 	 	146	 	 	 	65	 	 	 	50	 	 	 	(222	)	 	 	39	 	
Income/(losses) on discontinued operations, net of income tax expense	 	 	—	 	 	 	11	 	 	 	(3	)	 	 	—	 	 	 	8	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Income	 	$	146	 	 	$	76	 	 	$	47	 	 	$	(222	)	 	$	47	 	

(a)	 	All significant intercompany transactions have been eliminated in consolidation.	
45

Table of Contents
NRG Energy, Inc. and Subsidiaries
Condensed Consolidating Balance Sheet
December 31, 2005
(Unaudited)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantor	 	 	Non-Guarantor	 	 	NRG Energy, Inc.	 	 	 	 	 	 	Consolidated	 	
(In millions)	 	Subsidiaries	 	 	Subsidiaries	 	 	(Note Issuer)	 	 	Eliminations(1)	 	 	Balance	 	
ASSETS	
Current Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	(7	)	 	$	78	 	 	$	422	 	 	$	—	 	 	$	493	 	
Restricted cash	 	 	3	 	 	 	46	 	 	 	—	 	 	 	—	 	 	 	49	 	
Accounts receivable-trade, net	 	 	214	 	 	 	250	 	 	 	(205	)	 	 	—	 	 	 	259	 	
Current portion of notes receivable	 	 	—	 	 	 	25	 	 	 	468	 	 	 	(468	)	 	 	25	 	
Taxes receivable	 	 	(2	)	 	 	—	 	 	 	45	 	 	 	—	 	 	 	43	 	
Inventory	 	 	232	 	 	 	9	 	 	 	1	 	 	 	—	 	 	 	242	 	
Derivative instruments valuation	 	 	385	 	 	 	(1	)	 	 	3	 	 	 	—	 	 	 	387	 	
Collateral on deposit in support of energy risk management activities	 	 	438	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	438	 	
Deferred income taxes	 	 	6	 	 	 	(1	)	 	 	(5	)	 	 	—	 	 	 	—	 	
Prepayments and other current assets	 	 	65	 	 	 	17	 	 	 	38	 	 	 	—	 	 	 	120	 	
Assets held for sale	 	 	8	 	 	 	—	 	 	 	35	 	 	 	—	 	 	 	43	 	
Current assets — discontinued operations	 	 	—	 	 	 	98	 	 	 	—	 	 	 	—	 	 	 	98	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total current assets	 	 	1,342	 	 	 	521	 	 	 	802	 	 	 	(468	)	 	 	2,197	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net property, plant and equipment	 	 	2,176	 	 	 	413	 	 	 	31	 	 	 	—	 	 	 	2,620	 	
Other Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Investment in subsidiaries	 	 	787	 	 	 	—	 	 	 	1,774	 	 	 	(2,561	)	 	 	—	 	
Equity investments in affiliates	 	 	243	 	 	 	360	 	 	 	—	 	 	 	—	 	 	 	603	 	
Notes receivable	 	 	76	 	 	 	457	 	 	 	1,398	 	 	 	(1,473	)	 	 	458	 	
Intangible assets, net	 	 	238	 	 	 	19	 	 	 	—	 	 	 	—	 	 	 	257	 	
Derivative instruments valuation	 	 	18	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	18	 	
Funded letter of credit	 	 	—	 	 	 	—	 	 	 	350	 	 	 	—	 	 	 	350	 	
Deferred income taxes	 	 	—	 	 	 	26	 	 	 	—	 	 	 	—	 	 	 	26	 	
Other assets	 	 	22	 	 	 	19	 	 	 	83	 	 	 	—	 	 	 	124	 	
Non—current assets — discontinued operations	 	 	—	 	 	 	813	 	 	 	—	 	 	 	—	 	 	 	813	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total other assets	 	 	1,384	 	 	 	1,694	 	 	 	3,605	 	 	 	(4,034	)	 	 	2,649	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Assets	 	$	4,902	 	 	$	2,628	 	 	$	4,438	 	 	$	(4,502	)	 	$	7,466	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
LIABILITIES AND STOCK HOLDERS’ EQUITY	
Current Liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current portion of long-term debt	 	$	459	 	 	$	90	 	 	$	14	 	 	$	(468	)	 	$	95	 	
Accounts Payable	 	 	158	 	 	 	68	 	 	 	21	 	 	 	—	 	 	 	247	 	
Derivative instruments valuation	 	 	678	 	 	 	1	 	 	 	—	 	 	 	—	 	 	 	679	 	
Other bankruptcy settlement	 	 	—	 	 	 	3	 	 	 	—	 	 	 	—	 	 	 	3	 	
Accrued expenses and other current liabilities	 	 	60	 	 	 	42	 	 	 	69	 	 	 	—	 	 	 	171	 	
Current liabilities — discontinued operations	 	 	—	 	 	 	162	 	 	 	—	 	 	 	—	 	 	 	162	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total current liabilities	 	 	1,355	 	 	 	366	 	 	 	104	 	 	 	(468	)	 	 	1,357	 	
Other Liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term debt	 	 	1,397	 	 	 	620	 	 	 	1,866	 	 	 	(1,473	)	 	 	2,410	 	
Deferred income taxes	 	 	37	 	 	 	143	 	 	 	(51	)	 	 	—	 	 	 	129	 	
Derivative instruments valuation	 	 	25	 	 	 	11	 	 	 	20	 	 	 	—	 	 	 	56	 	
Out-of-market contracts	 	 	298	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	298	 	
Other long-term obligations	 	 	126	 	 	 	22	 	 	 	22	 	 	 	—	 	 	 	170	 	
Non-current liabilities — discontinued operations	 	 	—	 	 	 	568	 	 	 	—	 	 	 	—	 	 	 	568	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total non-current liabilities	 	 	1,883	 	 	 	1,364	 	 	 	1,857	 	 	 	(1,473	)	 	 	3,631	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total liabilities	 	 	3,238	 	 	 	1,730	 	 	 	1,961	 	 	 	(1,941	)	 	 	4,988	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Minority interest	 	 	—	 	 	 	1	 	 	 	—	 	 	 	—	 	 	 	1	 	
3.625% Preferred Stock	 	 	—	 	 	 	—	 	 	 	246	 	 	 	—	 	 	 	246	 	
Stockholders’ Equity	 	 	1,664	 	 	 	897	 	 	 	2,231	 	 	 	(2,561	)	 	 	2,231	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Liabilities and Stockholders’ Equity	 	$	4,902	 	 	$	2,628	 	 	$	4,438	 	 	$	(4,502	)	 	$	7,466	 	

(a)	 	All significant intercompany transactions have been eliminated in consolidation.	
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NRG Energy, Inc. and Subsidiaries
Condensed Consolidating Statements of Cash Flows
For the Six Months Ended June 30, 2005
(Unaudited)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantor	 	 	Non-Guarantor	 	 	 	 	 	 	 	 	 	 	Consolidated	 	
(In millions)	 	Subsidiaries	 	 	Subsidiaries	 	 	NRG Energy, Inc.	 	 	Eliminations (a)	 	 	Balance	 	
Cash Flows from Operating Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income	 	$	145	 	 	$	77	 	 	$	46	 	 	$	(221	)	 	$	47	 	
Adjustments to reconcile net income to net cash provided (used) by operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Distribution s in excess of (less than) equity in earnings of unconsolidated affiliates and consolidated subsidiaries	 	 	(30	)	 	 	(23	)	 	 	13	 	 	 	56	 	 	 	16	 	
Depreciation and amortization	 	 	67	 	 	 	25	 	 	 	4	 	 	 	—	 	 	 	96	 	
Amortization of financing costs and debt premium	 	 	—	 	 	 	3	 	 	 	2	 	 	 	—	 	 	 	5	 	
Write-off of deferred financing costs and debt premium	 	 	—	 	 	 	(9	)	 	 	1	 	 	 	—	 	 	 	(8	)	
Write downs and gains/losses on sale of equity method investments	 	 	—	 	 	 	(12	)	 	 	—	 	 	 	—	 	 	 	(12	)	
Deferred income taxes	 	 	(44	)	 	 	(2	)	 	 	42	 	 	 	—	 	 	 	(4	)	
Unrealized (gains)/losses on derivatives	 	 	71	 	 	 	11	 	 	 	(86	)	 	 	86	 	 	 	82	 	
Minority interest	 	 	—	 	 	 	1	 	 	 	—	 	 	 	—	 	 	 	1	 	
Amortization of power contracts and emission allowances	 	 	10	 	 	 	5	 	 	 	—	 	 	 	—	 	 	 	15	 	
Amortization of unearned equity compensation	 	 	1	 	 	 	1	 	 	 	3	 	 	 	—	 	 	 	5	 	
Gain on TermoRio settlement	 	 	—	 	 	 	(14	)	 	 	—	 	 	 	—	 	 	 	(14	)	
Cash used by changes in working capital, net of disposition affects	 	 	(6	)	 	 	12	 	 	 	(58	)	 	 	(86	)	 	 	(138	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Cash Provided/(used) by Operating Activities	 	 	214	 	 	 	75	 	 	 	(33	)	 	 	(165	)	 	 	91	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flows from Investing Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Proceeds on sale of equity method investments	 	 	—	 	 	 	65	 	 	 	—	 	 	 	—	 	 	 	65	 	
Decrease/(increase) in restricted cash and trust funds	 	 	—	 	 	 	26	 	 	 	—	 	 	 	—	 	 	 	26	 	
Decrease/(increase) in notes receivable	 	 	4	 	 	 	79	 	 	 	(103	)	 	 	113	 	 	 	93	 	
Capital expenditures	 	 	(30	)	 	 	(6	)	 	 	(1	)	 	 	—	 	 	 	(37	)	
Return of capital from equity investments	 	 	—	 	 	 	1	 	 	 	—	 	 	 	—	 	 	 	1	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Cash Provided/(used) by Investing Activities	 	 	(26	)	 	 	165	 	 	 	(104	)	 	 	113	 	 	 	148	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flows from Financing Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Proceeds from issuance of long-term debt, net	 	 	100	 	 	 	217	 	 	 	—	 	 	 	(113	)	 	 	204	 	
Payments for dividends	 	 	(150	)	 	 	(15	)	 	 	(8	)	 	 	165	 	 	 	(8	)	
Deferred debt issuance costs	 	 	—	 	 	 	—	 	 	 	(1	)	 	 	—	 	 	 	(1	)	
Principal payments on short and long-term debt	 	 	—	 	 	 	(304	)	 	 	(418	)	 	 	—	 	 	 	(722	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Cash Used by Financing Activities	 	 	(50	)	 	 	(102	)	 	 	(427	)	 	 	52	 	 	 	(527	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Effect of Exchange Rate Changes on Cash and Cash Equivalents	 	 	—	 	 	 	(3	)	 	 	—	 	 	 	—	 	 	 	(3	)	
Change in Cash from Discontinued Operations	 	 	—	 	 	 	(1	)	 	 	—	 	 	 	—	 	 	 	(1	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Change in cash and cash equivalents	 	 	138	 	 	 	134	 	 	 	(564	)	 	 	—	 	 	 	(292	)	
Cash and Cash Equivalents at Beginning of Period	 	 	156	 	 	 	203	 	 	 	712	 	 	 	—	 	 	 	1,071	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash and Cash Equivalents at End of Period	 	$	294	 	 	$	337	 	 	$	148	 	 	$	—	 	 	$	779	 	

(a)	 	All significant intercompany transactions have been eliminated in consolidation.	
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Item 2 — Management’s Discussion and Analysis of Financial Condition and Results of Operations
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Introduction
     NRG Energy, Inc., or “NRG”, “we”, “us” or the “Company”, 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 foreign. NRG has a diverse portfolio of electric generation facilities in terms of geography, fuel type and dispatch levels. NRG’s principal domestic generation assets 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, approximately 12% of the Company’s domestic generating facilities have dual or multiple fuel capacity, which allows plants to dispatch with the lowest cost fuel option. NRG has also acquired Padoma Wind Power LLC, which means it is likely that the Company will be investing in one or more domestic terrestrial wind projects.
     NRG’s 2005 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 the 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 and six months ended June 30, 2006 and 2005. 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:
 	•	 	NRG describes changes to the business environment during the period;	
 	 	 	 	
 	•	 	NRG highlights significant events that occurred in 2006 that are important to understanding the results of operations;	
 	 	 	 	
 	•	 	NRG then reviews the results of operations beginning with an overview of NRG’s total company results, followed by a more detailed review of those results by operating segment;	
 	 	 	 	
 	•	 	NRG then reviews the financial condition, addressing liquidity, the sources and uses of cash, capital resources and commitments;	
 	 	 	 	
 	•	 	NRG then discuss known trends that will affect NRG’s results of operations 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.
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Consolidated Results of Operations
     The following table provides selected financial information for NRG Energy, Inc., for the three and six months ended June 30, 2006 and 2005:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Three months ended June 30,	 	 	Six months ended June 30,	 	
(In millions except otherwise noted)	 	2006	 	 	2005	 	 	Change %	 	 	2006	 	 	2005	 	 	Change %	 	
 	
Operating Revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Energy revenue	 	$	739	 	 	$	320	 	 	 	131	%	 	$	1,294	 	 	$	686	 	 	 	89	%	
Capacity revenue	 	 	404	 	 	 	141	 	 	 	187	 	 	 	695	 	 	 	275	 	 	 	153	 	
Alternative revenue	 	 	47	 	 	 	46	 	 	 	2	 	 	 	99	 	 	 	95	 	 	 	4	 	
O & M fees	 	 	6	 	 	 	5	 	 	 	20	 	 	 	9	 	 	 	9	 	 	 	—	 	
Risk management activities	 	 	57	 	 	 	(5	)	 	NA	 	 	 	109	 	 	 	(36	)	 	NA	 	
Revenue contract amortization	 	 	226	 	 	 	1	 	 	NA	 	 	 	270	 	 	 	1	 	 	NA	 	
Other revenues	 	 	(56	)	 	 	14	 	 	NA	 	 	 	37	 	 	 	40	 	 	 	(8	)	
 	 	 	 	 	 	 	 	 	
Total operating revenues	 	 	1,423	 	 	 	522	 	 	 	173	 	 	 	2,513	 	 	 	1,070	 	 	 	135	 	
 	 	 	 	 	 	 	 	 	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cost of majority-owned operations	 	 	746	 	 	 	387	 	 	 	93	 	 	 	1,447	 	 	 	796	 	 	 	82	 	
Depreciation and amortization	 	 	178	 	 	 	41	 	 	 	334	 	 	 	297	 	 	 	83	 	 	 	258	 	
General, administrative and development	 	 	83	 	 	 	50	 	 	 	66	 	 	 	143	 	 	 	97	 	 	 	47	 	
Corporate relocation charges	 	 	—	 	 	 	1	 	 	NA	 	 	 	—	 	 	 	4	 	 	NA	 	
 	 	 	 	 	 	 	 	 	
Total operating costs and expenses	 	 	1,007	 	 	 	479	 	 	 	110	 	 	 	1,887	 	 	 	980	 	 	 	93	 	
 	 	 	 	 	 	 	 	 	
Operating income	 	 	416	 	 	 	43	 	 	 	867	 	 	 	626	 	 	 	90	 	 	 	596	 	
Other Income/(Expense)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Equity in earnings of unconsolidated affiliates	 	 	8	 	 	 	16	 	 	 	(50	)	 	 	29	 	 	 	53	 	 	 	(45	)	
Write downs and gains on sales of equity method investments	 	 	14	 	 	 	12	 	 	 	17	 	 	 	11	 	 	 	12	 	 	 	(8	)	
Other income, net	 	 	8	 	 	 	6	 	 	 	33	 	 	 	88	 	 	 	31	 	 	 	184	 	
Refinancing expenses	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(178	)	 	 	(35	)	 	 	(409	)	
Interest expense	 	 	(152	)	 	 	(46	)	 	 	(230	)	 	 	(266	)	 	 	(98	)	 	 	(171	)	
 	 	 	 	 	 	 	 	 	
Total other income/(expenses)	 	 	(122	)	 	 	(12	)	 	 	(917	)	 	 	(316	)	 	 	(37	)	 	 	(754	)	
Income from Continuing Operations before income tax expense	 	 	294	 	 	 	31	 	 	 	848	 	 	 	310	 	 	 	53	 	 	 	485	 	
Income tax expense	 	 	90	 	 	 	8	 	 	NA	 	 	 	89	 	 	 	14	 	 	 	536	 	
 	 	 	 	 	 	 	 	 	
Income from Continuing Operations	 	 	204	 	 	 	23	 	 	 	787	 	 	 	221	 	 	 	39	 	 	 	467	 	
Income from discontinued operations, net of income tax expense	 	 	(1	)	 	 	1	 	 	NA	 	 	 	8	 	 	 	8	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	
Net Income	 	$	203	 	 	$	24	 	 	 	846	 	 	$	229	 	 	$	47	 	 	 	387	 	
 	 	 	 	 	 	 	 	 	
Business Metrics	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Average natural gas price – Henry Hub (S/MMbtu)	 	 	6.88	 	 	 	6.94	 	 	 	(1	)%	 	 	7.28	 	 	 	6.69	 	 	 	9	%	

 	 	 	
NA — Not Applicable	
Significant Events Reflected in NRG’s Results of Operations during the six months ended June 30, 2006
 	•	 	On June 1, 2006, NRG entered into a sale and purchase agreement to sell its 100% owned Flinders power station and related assets, or Flinders. NRG has reclassified these assets as discontinued operations.	
 	 	 	 	
 	•	 	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. The results of operations of WCP were consolidated as of April 1, 2006, prior to which, NRG’s 50% ownership of WCP was recorded as equity earnings.	
 	 	 	 	
 	•	 	On February 2, 2006, NRG acquired Texas Genco LLC. Texas Genco LLC is now a wholly-owned subsidiary of NRG, and is managed and accounted for as a new business segment referred to as NRG Texas.	
 	 	 	 	
 	•	 	On January 31, 2006, NRG finalized a settlement agreement with an equipment manufacturer related to certain turbine purchase agreements. Upon finalization of the settlement, NRG recorded a total of $67 million of other income, of which $35 million was related to the discharge of accounts payable previously recorded and $32 million was related to the recording of the equipment at fair value.	
 	 	 	 	
 	•	 	NRG sold its interests in James River, Cadillac and SLAP for proceeds of approximately $42 million and a pre tax gain of $14 million. NRG also closed on the sale of Audrain to AmerenUE for a total purchase price of $115 million and a pre-tax gain of $10 million.	
 	 	 	 	
 	•	 	Total generation increased for the six months ended June 30, 2006 by 114% primarily due to the addition of NRG Texas to NRG’s total portfolio.	
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 	•	 	Improved operating performance and new tolling agreements contributed to $43 million of higher operating income from the South Central region.	
 	 	 	 	
 	•	 	An unseasonably mild winter and weakened power prices lowered generation demand for the Northeast region’s peaking and intermediate assets by 80% and 48%, respectively.	
 	 	 	 	
 	•	 	NRG recorded a gain of $67 million for the sale excess emission allowances.	
 	 	 	 	
 	•	 	NRG recorded $178 million in refinancing costs and $266 million in interest expense due to new debt facilities associated with the acquisition of Texas Genco.	
     For the benefit of the following discussions, the table below represents the results of NRG excluding the impact of NRG Texas and WCP for the three and six months ended June 30, 2006:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
For the three months ended June 30,	 	2006	 	 	2005	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	Total excluding	 	 	 	 	
(In millions)	 	Consolidated	 	 	NRG Texas(a)	 	 	WCP	 	 	NRG Texas/WCP	 	 	Consolidated	 	
 	
Energy revenue	 	$	739	 	 	$	439	 	 	$	27	 	 	$	273	 	 	$	320	 	
Capacity revenue	 	 	404	 	 	 	225	 	 	 	20	 	 	 	159	 	 	 	141	 	
Alternative revenue	 	 	47	 	 	 	—	 	 	 	—	 	 	 	47	 	 	 	46	 	
O & M fees	 	 	6	 	 	 	—	 	 	 	—	 	 	 	6	 	 	 	5	 	
Risk Management Activities	 	 	57	 	 	 	53	 	 	 	(1	)	 	 	5	 	 	 	(5	)	
Contract amortization	 	 	226	 	 	 	222	 	 	 	—	 	 	 	4	 	 	 	1	 	
Other revenues	 	 	(56	)	 	 	(30	)	 	 	3	 	 	 	(29	)	 	 	14	 	
 	
Total Operating revenues	 	 	1,423	 	 	 	909	 	 	 	49	 	 	 	465	 	 	 	522	 	
 	
Cost of majority-owned operations	 	 	746	 	 	 	418	 	 	 	36	 	 	 	292	 	 	 	387	 	
Depreciation and amortization	 	 	178	 	 	 	131	 	 	 	1	 	 	 	46	 	 	 	41	 	
General, administrative and development	 	 	83	 	 	 	32	 	 	 	5	 	 	 	46	 	 	 	50	 	
Corporate relocation charges	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1	 	
 	
Total operating costs and expenses	 	 	1,007	 	 	 	581	 	 	 	42	 	 	 	384	 	 	 	479	 	
 	
Operating income	 	$	416	 	 	$	328	 	 	$	7	 	 	$	81	 	 	$	43	 	

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
For the six months ended June 30,	 	2006	 	 	2005	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	Total excluding	 	 	 	 	
(In millions)	 	Consolidated	 	 	NRG Texas(a)	 	 	WCP (b)	 	 	NRG Texas	 	 	Consolidated	 	
 	
Energy revenue	 	$	1,294	 	 	$	641	 	 	$	27	 	 	$	626	 	 	$	685	 	
Capacity revenue	 	 	695	 	 	 	390	 	 	 	20	 	 	 	285	 	 	 	275	 	
Alternative revenue	 	 	99	 	 	 	—	 	 	 	—	 	 	 	99	 	 	 	95	 	
O & M fees	 	 	9	 	 	 	—	 	 	 	—	 	 	 	9	 	 	 	9	 	
Risk Management Activities	 	 	109	 	 	 	51	 	 	 	(1	)	 	 	59	 	 	 	(37	)	
Contract amortization	 	 	270	 	 	 	262	 	 	 	—	 	 	 	8	 	 	 	1	 	
Other revenues	 	 	37	 	 	 	3	 	 	 	3	 	 	 	31	 	 	 	42	 	
 	
Total Operating revenues	 	 	2,513	 	 	 	1,347	 	 	 	49	 	 	 	1,117	 	 	 	1,070	 	
 	
Cost of majority-owned operations	 	 	1,447	 	 	 	745	 	 	 	37	 	 	 	665	 	 	 	796	 	
Depreciation and amortization	 	 	297	 	 	 	205	 	 	 	1	 	 	 	91	 	 	 	83	 	
General, administrative and development	 	 	143	 	 	 	51	 	 	 	6	 	 	 	86	 	 	 	97	 	
Corporate relocation charges	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	4	 	
 	
Total operating costs and expenses	 	 	1,887	 	 	 	1,001	 	 	 	44	 	 	 	842	 	 	 	980	 	
 	
Operating income	 	$	626	 	 	$	346	 	 	$	5	 	 	$	275	 	 	$	90	 	

(a)	 	Financial information for the results of operations for NRG Texas is for the period of February 2, 2006 to June 30, 2006	
 	 	 	
(b)	 	Financial information for the results of operations for WCP is for the period of April 1, 2006 to June 30, 2006	
Management’s discussion of the results of operations for the three months ended June 30, 2006 and 2005
     Revenues from Majority-Owned Operations
     Total operating revenues from majority-owned operations rose by $901 million or 173%, from the second quarter of 2005 to $1.4 billion. Energy revenues comprised $739 million of the total, of which 65% was contracted compared to $320 million in the second quarter of 2005 of which 20% were contracted. The current quarter’s results were favorably impacted by the acquisition of NRG Texas, which contributed $909 million to operating revenues, and included $439 million of energy revenues and $222 million related to contract amortization from out-of-market power contracts. Additionally, the acquisition of Dynegy’s 50% interest in WCP, contributed $49 million to total operating revenues. Excluding NRG Texas and WCP, total operating revenues for the current quarter decreased by $57 million, as generation demand for the Northeast region’s intermediate and peaking plants decreased by a total of 56% compared to second quarter of 2005. Of the $57 million decline, $47 million was due to lower energy revenues as a result of lower power prices and generation volumes. Power prices in the Northeast regions’ two key New York markets fell by 12% and 7%. The South Central region’s total operating revenues declined by $15 million during the quarter to $94 million compared to the same period in 2005, primarily due to
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the netting of energy purchased for resale against merchant sales. For the second quarter of 2005, the South Central region purchased energy primarily to service its load obligations and not for resale.
     Capacity revenues for the three months ended June 30, 2006 increased by $263 million or 187%, compared to three months ended June 30, 2005. Of this increase, $225 million was related to NRG Texas primarily from PUCT auction sales. The remainder of the increase was due to $18 million from the Northeast New York assets where capacity prices increased from the second quarter of 2005 as well as a higher contract rate related to the Connecticut RMR settlement. In addition, capacity revenues increased to $20 million in the Western region primarily due to the acquisition of WCP and increased by $3 million in the South Central region.
     Risk management activities not afforded hedge accounting treatment resulted in a total derivative gain of $57 million for the three months ended June 30, 2006. This was comprised of $10 million in financial revenue losses and $67 million of mark-to-market gains. The $10 million loss of financial revenues represents the settled value for the quarter of financial instruments that were not afforded hedge accounting treatment. Of the $67 million of mark-to-market gains, $37 million represents the change in fair value of forward sales of electricity and fuel, and $17 million represents the reversal of mark-to-market losses which ultimately settled as financial revenues. Additionally, we recognized a $13 million gain associated with our trading activity. These activities primarily support the Northeast and Texas regions’ assets.
     The following table shows the Company’s risk management activities that were not afforded hedge accounting treatment for the three months ended June 30, 2006.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Three months ended June 30, 2006	 	 	Three months ended June 30, 2005	 	
 	 	 	 	 	 	 	 	 	 	South	 	 	All	 	 	 	 	 	 	 	 	 	 	 	 	 	 	South	 	 	All	 	 	 	 	
(In millions)	 	Texas	 	 	Northeast	 	 	Central	 	 	Other	 	 	Total	 	 	Texas	 	 	Northeast	 	 	Central	 	 	Other	 	 	Total	 	
 	 	 	 	
Net gains/(losses) on settled positions, or financial revenues	 	$	—	 	 	$	(11	)	 	$	1	 	 	$	—	 	 	$	(10	)	 	$	—	 	 	$	(2	)	 	$	—	 	 	$	—	 	 	$	(2	)	
 	 	 	 	
Mark-to-market results	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reversal of previously recognized unrealized gains/(losses) on settled positions	 	 	—	 	 	 	17	 	 	 	—	 	 	 	—	 	 	 	17	 	 	 	—	 	 	 	(8	)	 	 	—	 	 	 	—	 	 	 	(8	)	
Net unrealized gains/(losses) on open positions related to economic hedges	 	 	45	 	 	 	(5	)	 	 	(2	)	 	 	(1	)	 	 	37	 	 	 	—	 	 	 	6	 	 	 	—	 	 	 	(1	)	 	 	5	 	
Net unrealized gains on open positions related to trading activity	 	 	8	 	 	 	5	 	 	 	—	 	 	 	—	 	 	 	13	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	
Subtotal mark-to-market results	 	 	53	 	 	 	17	 	 	 	(2	)	 	 	(1	)	 	 	67	 	 	 	—	 	 	 	(2	)	 	 	—	 	 	 	(1	)	 	 	(3	)	
Total derivative gain/(losses)	 	$	53	 	 	$	6	 	 	$	(1	)	 	$	(1	)	 	$	57	 	 	$	—	 	 	$	(4	)	 	$	—	 	 	$	(1	)	 	$	(5	)	
 	 	 	 	
     Since these risk management 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 costs of energy. Over the course of 2005, NRG hedged much of its calendar year 2006 Northeast generation. Since that time, the settled and forward prices of electricity decreased, resulting in the recognition of mark-to-market forward sales and the settlement of such positions as gains.
     Cost of Majority-Owned Operations
     Cost of majority-owned operations includes cost of energy, operating and maintenance expenses, and non-income tax expenses. For the three months ended June 30, 2006, cost of majority-owned operations was $746 million or 52% of total operating revenues compared to $387 million, or 74%, of total operating revenues for the comparable period in 2005, an increase of $359 million or 93%. This increase in absolute terms but decrease in related percentage terms was primarily due to NRG Texas which incurred $418 million, or 46%, of total operating revenues in cost of majority-owned operations. Cost of energy increased from $273 million for the three months ended June 30, 2005 to $518 million for the three months ended June 30, 2006. The increase was primarily due to NRG Texas which recognized $310 million in cost of energy. Additionally, WCP’s cost of energy for the second quarter of 2006 was $26 million. Excluding NRG Texas and WCP, cost of energy decreased by $91 million. This decrease was driven by $35 million in lower cost of energy in the Northeast region primarily due to lower oil and gas fuel costs related to lower generation from oil- and gas-fired assets of approximately 59% and 53% respectively. The South Central region’s cost of energy was lower this quarter compared to the same period in 2005 by $22 million primarily due to netting of purchased energy against merchant sales this quarter.
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     Other operating costs during the second quarter of 2006 were $228 million compared to $114 million for the second quarter of 2005. This increase was primarily driven by other operating costs related to NRG Texas of $108 million and WCP of $10 million. Additionally, major maintenance for the Northeast region’s New York assets increased by $7 million due to increased maintenance focused on improved reliability. This was partially offset by an $18 million accrual reversal relating to a favorable court decision related to station service obligations at the Western New York plants.
     Depreciation and Amortization
     NRG’s depreciation and amortization expense for the three months ended June 30, 2006 and 2005 was $178 million and $41 million, respectively. The increase in depreciation and amortization from was primarily due to the acquisition of NRG Texas.
     General, Administrative and Development
     NRG’s general, administrative and development, or G&A, costs for the three months ended June 30, 2006 were $83 million or 6% of total operating revenues compared to $50 million or 10% of total operating revenue for the three months ended June 30, 2005. These costs are primarily comprised of corporate labor, insurance and external professional support, such as legal, accounting and audit fees. G&A cost at NRG Texas were $15 million excluding corporate allocations and was $4 million at WCP. Corporate G&A recognized for the second quarter of 2006 was $44 million compared to $27 million for the second quarter of 2005. The $17 million increase was due to $6 million of non-recurring expenses related to the unsolicited takeover attempt offer by Mirant Corporation and $5 million of non-recurring costs associated with the Texas integration efforts. The remainder of the increase at Corporate was related to higher labor and consulting expenses which were partially offset by lower insurance expenses.
     Equity in Earnings of Unconsolidated Affiliates
     For the three months ended June 30, 2006, NRG recorded $8 million in equity earnings from the Company’s investments in unconsolidated affiliates, a 50% decrease from the comparable period last year of $16 million. Of the $8 million decrease, $6 million was due to the acquisition of Dynegy’s 50% interest in WCP – $4 million due to the consolidation of WCP earnings– and the sale of NRG’s 50% interest in Rocky Road LLC to Dynegy – representing $2 million of the decline in equity in earnings of unconsolidated affiliates. Additionally, NRG’s Saguaro investment earnings decreased by $2 million, as its gas supply contract expired at the end of June 2005 requiring the plant to purchase gas in the spot market at higher prices.
     Gains on Sales of Equity Method Investments
     For the three months ended June 30, 2006, NRG realized approximately $14 million of gains on sales of equity method investments, compared to $12 million of gains on sales of equity method investments in the second quarter of 2005. During the second quarter of 2006 NRG sold its interests in Cadillac and certain investments in South and Latin American power funds for a gain of approximately $11 million and $3 million, respectively. For the comparable period of 2005, NRG sold its investment in Enfield for a gain of approximately $12 million. For a further discussion see Note 4 to the condensed consolidated financial statements of this Form 10-Q.
     Other income, net
     For the three months ended June 30, 2006 and 2005, NRG recorded other income of $8 million and $6 million, respectively. Other income is primarily comprised of interest income, of which NRG recorded $7 million and $6 million for the second quarter of 2006 and 2005, respectively. The favorable increase in interest income this quarter compared to the second quarter of 2005 was related to more efficient management of NRG cash balances.
     Interest expense
     Interest expense for the three months ended June 30, 2006 was $152 million compared to $46 million, for the three months ended June 30, 2005. Interest expense increased due to the servicing of new debt issued to finance the acquisition of NRG Texas. For further discussion of the acquisition and financing thereof, see Notes 3 and 8 to the condensed consolidated financial statements of this Form 10-Q.
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     Income Tax Expense
     Income tax expense was $90 million and $8 million for the three months ended June 30, 2006 and 2005, respectively. The effective tax rate was 30.8% and 25.8% for the three months ended June 30, 2006 and 2005, respectively. The effective income tax rate for the three months ended June 30, 2006 differs from the U.S. statutory rate of 35% due to a property basis difference relating to disbursements from the disputed claims reserve, subpart F income and dividends, and earnings in foreign jurisdictions that are taxed at rates lower than the U.S. statutory rate.
     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 No. 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 Taxes
     NRG classified as discontinued operations the operations and gains/losses recognized on the sale of projects that were sold or were deemed to have met the required criteria for such classification pending final disposition. For the three months ended June 30, 2006, NRG recorded a loss from discontinued operations of $1 million, net of income tax expense compared to a gain of $1 million for the prior comparable period. For the three months ended June 30, 2006, discontinued operations consisted of the results of the Company’s 100% owned Flinders power station and Audrain. For the second quarter of 2005, discontinued operations consisted of the results of NRG McClain LLC, Flinders, and Audrain. NRG anticipates closing the sale of Flinders during the fourth quarter of 2006.
Management’s discussion of the results of operations for the six months ended June 30, 2006 and 2005
     Revenues from Majority-Owned Operations
     Total operating revenues from majority-owned operations was $2.5 billion for the six months ended June 30, 2006; an increase of 135% compared to the six months ended June 30, 2005 of $1.1 billion. Total operating revenues for the six months ended June 30, 2006 included $1.3 billion of energy revenues an 89% increase over the comparable period in 2005. Of the $1.3 billion in energy revenues, 58% was contracted compared to 17% for the six months ended June 2005. This increase was primarily due to the acquisition of NRG Texas. NRG Texas recorded $1.3 billion of total operating revenues for the six months ended June 30, 2006. Of this amount, $641 million were energy revenues, of which 92% were contracted. Excluding the results of NRG Texas and WCP, total operating revenues for the six months ended June 30, 2006 was $1.1 billion, of which $626 million was energy revenues, a decrease of $59 million compared to the six months ended June 30, 2005. The decline in energy revenues was primarily due to lower generation and power prices in the Northeast region. Total generation in the Northeast region declined by 17% from the comparable period of 2005 reducing energy revenues by $92 million due to decreased generation demand from NRG’s peaking oil-fired and intermediate gas-fired plants, as an unseasonably mild winter weakened power prices and demand in the region. Average power prices in NRG’s two key New York markets declined by 8% and 2% for the six months ended June 30, 2006 compared to the same period in 2005. The decrease in the Northeast region was partially offset by a $32 million increase from the South Central region’s energy revenues as power prices in the Entergy region increased by approximately 5% for the six months ended June 30, 2006 compared to the same period in 2005. In addition, generation from NRG’s South Central plants increased by 12% over the comparable prior period.
     Capacity revenues for the six months ended June 30, 2006 was $695 million compared to $275 million for the six months ended June 30, 2005, an increase of $420 million or 153%. The increase was largely due to capacity revenues related to NRG Texas of $390 million and WCP of $20 million. Excluding NRG Texas and WCP, capacity revenues increased by $10 million. Capacity revenues from the Northeast region increased by approximately $11 million due to higher New York capacity prices and higher rates related to the Connecticut RMR settlement agreement and the South Central region saw increases in capacity revenues of approximately $6 million due to new tolling agreements. This was partially offset by a decline in capacity revenues related to the expiration of a contract at Rockford in May 2005.
     For the six months ended June 30, 2006, other revenues decreased by $11 million, excluding NRG Texas and WCP impacts. Of this decrease, $69 million was due to the netting of gas purchases from cost of majority-owned operations against revenues, which had no impact on total margins. This was offset by $67 million in additional revenues from emission sales to third parties in lieu of generation, primarily in the first quarter of 2006, due to an unseasonably mild winter.
     Risk management activities resulted in a total derivative gain of $109 million for the six months ended June 30, 2006. This was comprised of $8 million in financial revenue losses and $117 million of mark-to-market gains. The $8 million loss on financial revenues represents the settled value for the six months ended June 30, 2006 of financial instruments that were not afforded hedge accounting treatment. Of the $117 million of mark-to-market gains, $67 million represents the change in fair value of forward sales of electricity and fuel, and $38 million represents the reversal of mark-to-market losses which ultimately settled as financial revenues. Additionally, we recognized a $12 million gain associated with trading activities. These activities primarily support the Northeast and Texas region’s assets.
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     The following table shows the Company’s hedging and risk management activities that were not afforded hedge accounting treatment for the six months ended June 30, 2006.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Six months ended June 30, 2006	 	 	Six months ended June 30, 2005	 	 	
 	 	 	 	 	 	 	 	 	 	South	 	 	All	 	 	 	 	 	 	 	 	 	 	 	 	 	 	South	 	 	All	 	 	 	 	 	
(In millions)	 	Texas	 	 	Northeast	 	 	Central	 	 	Other	 	 	Total	 	 	Texas	 	 	Northeast	 	 	Central	 	 	Other	 	 	Total	 	 	
 	
Net gains/(losses) on settled positions, or financial revenues	 	$	—	 	 	$	(12	)	 	$	4	 	 	$	—	 	 	$	(8	)	 	$	—	 	 	$	47	 	 	$	—	 	 	$	—	 	 	$	47	 	 	 	
 	
Mark-to-market results	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reversal of previously recognized unrealized gains/(losses) on settled positions	 	 	—	 	 	 	38	 	 	 	—	 	 	 	—	 	 	 	38	 	 	 	—	 	 	 	(50	)	 	 	—	 	 	 	—	 	 	 	(50	)	 	 	
Net unrealized gains/(losses) on open positions related to economic hedges	 	 	43	 	 	 	25	 	 	 	—	 	 	 	(1	)	 	 	67	 	 	 	—	 	 	 	(33	)	 	 	—	 	 	 	—	 	 	 	(33	)	 	 	
Net unrealized gains on open positions related to trading activity	 	 	8	 	 	 	4	 	 	 	—	 	 	 	—	 	 	 	12	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	
 	
Subtotal mark-to-market results	 	 	51	 	 	 	67	 	 	 	—	 	 	 	(1	)	 	 	117	 	 	 	—	 	 	 	(83	)	 	 	—	 	 	 	—	 	 	 	(83	)	 	 	
Total derivative gain/(losses)	 	$	51	 	 	$	55	 	 	$	4	 	 	$	(1	)	 	$	109	 	 	$	—	 	 	$	(36	)	 	$	—	 	 	$	—	 	 	$	(36	)	 	 	
 	
     Cost of Majority-Owned Operations
     Cost of majority-owned operations for the six months ended June 30, 2006 was $1.4 billion or 58% of total operating revenues. Cost of majority-owned operations for the six months ended June 30, 2005 was $796 million or 74% of total operating revenues from majority-owned operations. The increase was primarily due to the acquisition of NRG Texas and WCP, of which NRG Texas recorded cost of majority-owned operations of $745 million and WCP recorded $37 million. Excluding NRG Texas and WCP, cost of majority-owned operations decreased by $131 million, driven primarily by a $129 million decline in cost of energy to $447 million for the six months ended June 30, 2006. This was due to a 17% decrease in generation in the Northeast region which drove fuel oil and gas costs down by $71 million and $87 million, respectively. Partially offsetting this decrease was higher coal costs in the Northeast region of $23 million primarily due to a 2% increase in coal-fired generation and the increased costs of eastern coal, which is still burned as a blend by the Indian River plant.
     Other operating costs increased by $195 million to $414 million, $185 million related to the acquisition of NRG Texas and $11 million related to WCP. Excluding the impact of NRG Texas and WCP, other operating costs were essentially flat. Operating and Maintenance costs benefited in the second quarter of 2006 from an accrual reversal of $18 million related to a favorable court decision in a station service dispute at NRG’s Western New York plants. This accrual reversal was offset by $8 million of higher major maintenance in the Northeast region related to maintenance activities to improve plant reliability and additional outage work at our Oswego plant. Labor, normal maintenance and property taxes comprised of the balance of the increase.
     Depreciation and Amortization
     NRG’s depreciation and amortization expense for the six months ended June 30, 2006 and 2005 was $297 million and $83 million, respectively. NRG Texas depreciation and amortization made up $205 million of the $214 million increase.
     General, Administrative and Development
     NRG’s G&A costs for the six months ended June 30, 2006 were $143 million compared to $97 million for the six months ended June 30, 2005. Corporate costs represented $70 million or 3% of total operating revenues and $51 million or 5% of total operating revenues for the periods ended June 30, 2006 and 2005, respectively. G&A costs were adversely impacted by $6 million of costs associated with the unsolicited takeover offer by Mirant Corporation, $7 million of NRG Texas integration costs, and $2 million of bad debt expense, partially offset by lower insurance costs. The balance of the total increase in G&A was due to the of acquisition NRG Texas, which recorded $26 million in related G&A costs for the six months ended June 30, 2006.
     Equity in Earnings of Unconsolidated Affiliates
     For the six months ended June 30, 2006, equity earnings from NRG’s investments in unconsolidated affiliates were $29 million compared to $53 million for the six months ended June 30, 2005, a decline of 45%. The decline in earnings was largely due to a number of sales of investments NRG completed over the past year. NRG’s earnings in WCP accounted for $7 million of the decline as the results of WCP were fully consolidated as of March 31, 2005, the date of the purchase of Dynegy’s 50% interest. As part of that transaction, NRG sold its 50% interest in the Rocky Road investment, which accounted for $2 million of the decline in total equity earnings. Additionally, the Enfield investment, which was sold on April 1, 2005, earned $16 million for the six months ended June 30, 2005. Other sales of equity investments included James River and Cadillac.
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     Gains/(Losses) on Sales of Equity Method Investments
     For the six months ended June 30, 2006, NRG sold its interest in James River, Cadillac, and its interests in certain Latin American power funds for a pre-tax loss of $3 million, a pre-tax gain of $11 million and a pre-tax gain of $3 million, respectively. For the six month ended June 30, 2005, NRG sold its 25% interest in its Enfield investment for a pre-tax gain of $12 million.
     Other income, net
     Other income increased by $57 million or 184% for the six months ended June 30, 2006 compared to the same period in 2005. Other income in 2006 was favorably impacted by $67 million of other income associated with the settlement with an equipment manufacturer related to turbine purchase agreements entered into in 1999 and 2001. In 2005, NRG recorded a $14 million gain from the settlement related to the Company’s TermoRio project in Brazil and a contingent gain of $4 million related to the sale of a former project, the Crockett Cogeneration Facility, which was sold in 2002. Other income was also favorably impacted by $5 million of higher interest income related to more efficient management of cash balances.
     Refinancing expense
     Refinancing expenses for the six months ended June 30, 2006 and 2005 were $178 million and $35 million, respectively. In the first half of 2006, NRG acquired NRG Texas for a purchase price of approximately $6.2 billion. NRG partially financed this purchase through borrowings under new debt facilities and repaid and terminated previous debt facilities. As a result of this financing, NRG incurred $178 million of refinancing expenses for the six months ended June 30, 2006. Of the $178 million, $127 million was related to the premium paid to NRG’s previous debt holders, $33 million for the amortization of a bridge loan commitment entered into on September 30, 2005, and $31 million related to write-offs of deferred financing costs associated with NRG’s previous debt, and a credit of $14 million related to a debt premium write-off.
     In the first half of 2005, NRG redeemed and purchased a total of approximately $416 million of the Company’s Second Priority Notes. As a result of the redemption and purchases, NRG incurred approximately $35 million in premiums and write-offs of deferred financing costs. Additionally, projects in the Company’s Australia region refinanced their project debt during the first six months of 2005 resulting in the write-off of approximately $10 million of debt premium.
     Interest expense
     Interest expense for the six months ended June 30, 2006 was $266 million as compared to $98 million for the six months ended June 30, 2005. The increase in interest expense was essentially due to interest on new debt issued to finance the acquisition of NRG Texas. See Notes 3 and 8 to the condensed consolidated financial statements of this Form 10-Q for a further discussion of the acquisition and the related financing. As part of the refinancing, NRG replaced its previous senior secured term loan with a new $3.575 billion senior secured term loan. Additionally, NRG retired $1.1 billion of its 8% Second Priority Notes and issued $3.6 billion in senior unsecured notes with a weighted average interest rate of 7.33%.
     In the first quarter of 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 any impact associated with ineffectiveness was immaterial to NRG financial results. For the six months ended June 30, 2006, NRG had deferred gains of $59 million in other comprehensive income. See Note 8 to the condensed consolidated financial statements of this Form 10-Q for a further discussion on these interest rate swaps.
     Additionally, NRG designated an existing fixed-to-floating interest rate swap, previously as a hedge of NRG’s 8% Second Priority Notes, into a fair value hedge of the new Senior Notes which NRG closed on February 2, 2006. For the three months ended June 30, 2006, NRG did not recognize any ineffectiveness associated with this hedging relationship. For the six months ended June 30, 2006, NRG recognized $3 million in. ineffectiveness associated with this hedging relationship. NRG does not foresee any ineffectiveness of this hedging relationship in the future.
     Income Tax Expense
     Income tax expense was $89 million and $14 million for the six months ended June 30, 2006 and 2005, respectively. The overall effective tax rate was 28.7% and 26.4% for the six months ended June 30, 2006 and 2005, respectively. The effective income tax rate for the six months ended June 30, 2006 and 2006 differs from the U.S. statutory rate of 35% due to a property basis difference relating to disbursements from the disputed claims reserve, subpart F income and dividends, and earnings in foreign jurisdictions that are taxed at rates lower than the U.S. statutory rate. NRG’s 2005 domestic income tax expense partially offset the low foreign effective tax rate due to the subpart F inclusion and taxation for the Company’s gain on the sale of Enfield, of approximately $12 million.
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     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 No. 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 Taxes
     NRG classified as discontinued operations the operations and gains/losses recognized on the sale of projects that were sold or were deemed to have met the required criteria for such classification pending final disposition. For the six months ended June 30, 2006 and 2005, NRG recorded income from discontinued operations, net of income tax expense of $8 million for both periods. Discontinued operations for the six months ended June 30, 2006 was comprised of the results of Flinders and Audrain. Discontinued operations for the six months ended June 30, 2005,consisted of the results of the Flinders, Audrain and NRG McClain LLC. As of June 30, 2006, Flinders had not yet been sold.
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Business Segment Results
     NRG’s identified reportable segments are primarily based on geographic areas, both domestic and foreign. On February 2, 2006 NRG acquired Texas Genco LLC now referred to as NRG Texas creating a new segment of operations – Wholesale Power Generation – Texas.
     The following is a detailed discussion of the results of operations of NRG’s wholesale power generation business segments.
Texas Region
     For a discussion of the business profile of the Texas region, see pages 19-23 of NRG Energy Inc’s. 2005 Annual Report on Form 10-K.
 	 	 	 	 	 	 	 	 	
Selected income statement data	 	Three months ended June 30,	 	 	Period ended June 30,	 	
(In millions except otherwise noted)	 	2006	 	 	2006(a)	 	
 	
Operating Revenues	 	 	 	 	 	 	 	 	
Energy revenue	 	$	439	 	 	$	641	 	
Capacity revenue	 	 	225	 	 	 	390	 	
Alternative revenue	 	 	—	 	 	 	—	 	
O & M fees	 	 	—	 	 	 	—	 	
Risk Management Activities	 	 	53	 	 	 	51	 	
Contract amortization	 	 	222	 	 	 	262	 	
Other revenues	 	 	(30	)	 	 	3	 	
 	
Total operating revenues	 	 	909	 	 	 	1,347	 	
 	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	
Cost of energy	 	 	310	 	 	 	560	 	
Depreciation and amortization	 	 	131	 	 	 	205	 	
Other operating expenses	 	 	140	 	 	 	236	 	
 	
Operating income/(loss)	 	$	328	 	 	$	346	 	
 	
MWh sold (in thousands)	 	 	12,742	 	 	 	20,055	 	
Business Metrics	 	 	 	 	 	 	 	 	
Average on-peak market power prices ($/MWh)	 	 	66.71	 	 	 	60.28	 	
Cooling Degree Days, or CDDs(a)	 	 	1,012	 	 	 	1,126	 	
CDD’s 30 year rolling average	 	 	857	 	 	 	857	 	
Heating Degree Days, or HDDs(a)	 	 	47	 	 	 	993	 	
HDD’s 30 year rolling average	 	 	1,382	 	 	 	1,382	 	

(a)	 	For the period February 2, 2006 to June 30, 2006 only.	
Quarterly Results
     Operating Income
     For the three months ended June 30 2006, operating income for NRG Texas was $328 million. Total generation for the quarter was 12.6 million MWh, nearly doubling NRG’s domestic generation from the prior comparable quarter of 2005. NRG Texas achieved total sales volumes for the second quarter of 2006 of 12.7 million MWh of which 74% were sold under long-term agreements. The difference between MWh sold and MWh generated represents MWh purchased from the marketplace.
     Revenues
     Total operating revenues from the Texas region for the three months ended June 30, 2006 were $909 million. Operating revenues included $439 million in energy revenues of which 88% were contracted. Capacity revenues totaled $225 million of which $95 million was related to investments in the STP nuclear generation facility. Additionally, NRG Texas recorded $222 million of contract amortization related to out of market contracts assumed upon the acquisition.
     Risk Management Activity – The total derivative gain for the quarter was $53 million, reflecting the partial ineffectiveness of forward hedge positions.
     Cost of Energy
     Cost of energy at NRG Texas was $310 million for the three months ended June 30, 2006. Coal and lignite costs were $123 million for the period, gas fuel costs were $176 million and nuclear fuel-related expenses were $11 million. These costs directly relate
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to the generation from the Texas region’s coal-fired, gas-fired and nuclear-fired units. Coal costs included $44 million of lignite coal used at the Limestone coal plant. Purchased energy was $4 million higher or $45 per megawatt/hour and represented the cost to procure additional MWh’s to cover contracted obligations during planned outages for the second quarter of 2006. Also included in Cost of energy were an emissions allowance expense of $4 million and a credit of $11 million in cost contract amortization for the quarter.
     Other Operating Expenses
     Other operating expenses for the Texas region for the period ended June 30, 2006 was $140 million or 15% of the region’s total operating revenues. These costs include $89 million of operating and maintenance costs of which 50% represents normal and major maintenance and $19 million of property tax expense. In addition, NRG Texas incurred $32 million of G&A expense, of which $17 million was related to corporate allocations.
Year-to-date Results
     Operating Income
     For the period ended June 30, 2006, which includes results since the acquisition date of February 2, 2006, operating income for Texas region was $346 million. These results were largely driven by $390 million of capacity revenues, energy margins of $641 million, and power contract amortization of $262 million. The Texas region’s total generation for the period was 19 million MWh. Total sales volume for the period totaled 20 million MWh, of which 78% were sold under long-term sales agreements. NRG Texas purchased approximately 1 million MWh from the marketplace.
     Revenues
     Total operating revenues totaled $1.3 billion for the period ended June 30, 2006. Operating revenues include $641 million in energy revenues of which 92% were contracted. Capacity revenues were $390 million, of which $161 million was related to the STP nuclear generation facility. Additionally, NRG Texas recorded $262 million of contract amortization related to out-of-market contracts assumed upon acquisition.
     Risk Management Activity – The total derivative gain for the period was $51 million, reflecting the partial ineffectiveness of our forward hedge positions.
     Cost of Energy
     Cost of energy for the Texas region was $560 million for the period. Coal and lignite costs were $198 million, the cost of gas was $228 million and nuclear fuel expense was $15 million. These costs represent direct fuel-related costs for the generation of power from the Texas region. Purchased energy was $52 million, averaging $59 per MWh acquired to cover contracted obligations. Also included in cost of energy was an emissions allowance expense of $17 million and $50 million in coal contract amortization for the period ended June 30, 2006.
     Other Operating Expenses
     Other operating expenses for the period ended June 30, 2006 were $236 million or 18% of total operating revenues. This included $155 million of operating and maintenance costs, 53% of which was related to normal and major maintenance and $30 million of property tax expense. G&A expense was $51 million for the period, including $25 million of charges related to corporate allocations.
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Northeast Region
     For a discussion of the business profile of the Northeast region, see pages 23-25 of NRG Energy Inc’s. 2005 Annual Report on Form 10-K.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Three months ended June 30,	 	 	Six months ended June 30,	 	
(In millions except otherwise noted)	 	2006	 	 	2005	 	 	Change %	 	 	2006	 	 	2005	 	 	Change %	 	
 	
Operating Revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Energy revenue	 	$	198	 	 	$	237	 	 	 	(16	)%	 	$	421	 	 	$	513	 	 	 	(18	)%	
Capacity revenue	 	 	91	 	 	 	73	 	 	 	25	 	 	 	149	 	 	 	138	 	 	 	8	 	
Risk Management Activities	 	 	6	 	 	 	(4	)	 	NA	 	 	 	55	 	 	 	(36	)	 	NA	 	
Other revenues	 	 	8	 	 	 	10	 	 	 	(20	)	 	 	70	 	 	 	33	 	 	 	112	 	
 	 	 	 	 	 	 	 	 	
Total operating revenues	 	 	303	 	 	 	316	 	 	 	(4	)	 	 	695	 	 	 	648	 	 	 	7	 	
 	 	 	 	 	 	 	 	 	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cost of energy	 	 	123	 	 	 	158	 	 	 	(22	)	 	 	249	 	 	 	343	 	 	 	(27	)	
Other operating expenses	 	 	91	 	 	 	100	 	 	 	(9	)	 	 	185	 	 	 	195	 	 	 	(5	)	
Depreciation and amortization	 	 	22	 	 	 	18	 	 	 	22	 	 	 	44	 	 	 	37	 	 	 	19	 	
Operating income	 	$	67	 	 	$	40	 	 	 	72	 	 	$	217	 	 	$	73	 	 	 	197	 	
 	 	 	 	 	 	 	 	 	
MWh sold (in thousands)	 	 	2,820	 	 	 	3,173	 	 	 	(11	)	 	 	6,081	 	 	 	7,348	 	 	 	(17	)	
Business Metrics	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Average on-peak market power prices ($/MWh)	 	 	67.71	 	 	 	74.20	 	 	 	(9	)	 	 	70.35	 	 	 	72.84	 	 	 	(3	)	
Cooling Degree Days, or CDDs(a)	 	 	280	 	 	 	336	 	 	 	(17	)	 	 	280	 	 	 	336	 	 	 	(17	)	
CDD’s 30 year rolling average	 	 	209	 	 	 	209	 	 	 	—	 	 	 	209	 	 	 	209	 	 	 	—	 	
Heating Degree Days, or HDDs(a)	 	 	1,431	 	 	 	1,677	 	 	 	(15	)	 	 	6,913	 	 	 	8,051	 	 	 	(14	)	
HDD’s 30 year rolling average	 	 	7,869	 	 	 	7,869	 	 	 	—	 	 	 	7,869	 	 	 	7,869	 	 	 	—	 	

(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.	
Quarterly Results
     Operating Income
     Operating income for the Northeast region for the three months ended June 30, 2006 increased by $27 million or 72% to $67 million, despite an 11% decrease in generation. However, unit operating performance across the wholly owned regional fleet improved as measured by EFOR to 6.23% compared to 7.42% in the second quarter 2005. During the second quarter of 2006 lower generation combined with weaker power prices in the key New York markets in the Northeast region accounted for a 16% drop in energy revenues compared to the comparable prior quarter. Increased capacity revenues reflected higher capacity prices in the New York and Connecticut markets compared to the second quarter of 2005. Operating income for the second quarter of 2006 benefited from lower cost of energy of approximately $35 million or 22% compared to the same period in 2005, primarily due to lower generation at the oil-fired plants at Oswego and Connecticut. In addition, a 33% increase in the price of crude oil compared to the second quarter of 2005 made many of these units uneconomic to run. Coal based generation in the quarter however was up almost 0.2 million MWhs primarily due to the Indian River plant which had an extended outage during the comparable period in 2005. Other operating expenses were $91 million, 9% lower than second quarter of 2005 due mainly to an $18 million financial benefit of a favorable court decision related to station service obligations at the Western New York plants combined with $3 million lower corporate allocation as a result of the inclusion of NRG Texas into the NRG portfolio.
     Revenues
     Total operating revenues from the Northeast region was $303 million for the three months ended June 30, 2006 compared to $316 million for the three months ended June 30, 2005, a 4% decrease. Revenues for the three months ended June 30, 2006 included $198 million in energy revenues compared to $237 million for the three months ended June 30, 2005. This unfavorable decrease was due to lower generation from NRG’s gas-fired and oil-fired plants of 53% and 59%, respectively, partially offset by a 27% increase in generation at the PJM facilities. Despite above normal temperatures the decline in generation in the second quarter of 2006 was due to lower power prices compared to the prior comparable period in 2005. Capacity revenues for the three months ended June 30, 2006 increased 25% to $91 million compared to $73 million for the three months ended June 30, 2005. The increase was primarily due to a new RMR agreement at several of the Connecticut facilities at higher approved rates than those prevailing during the second quarter of 2005. In addition, New York State capacity prices for May and June of 2006 have cleared at higher rates than in the prior comparable period in 2005.
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     Cost of Energy
     Cost of energy in the Northeast was $123 million compared to $158 million in 2005, a decrease of $35 million or 22%. Oil costs in the Company’s Northeast region decreased by $21 million reflecting reduced generation from the oil-fired plants. Similarly, gas costs of $32 million decreased by $23 million over the second quarter of 2005 primarily due to lower generation from the New York City plants. However, coal costs in the Northeast region increased by $12 million, due to higher generation and higher coal prices in the second quarter of 2006 from the Indian River plant compared to the same quarter of 2005.
     Other Operating Expenses
     Other operating expenses include O&M expenses, non-income based taxes, and general & administrative expenses or G&A. Other operating expenses for the Northeast region were $91 million for the second quarter 2006 compared to $100 million in the second quarter 2005. The $9 million decrease in O&M expenses this quarter compared to the second quarter 2005 was due to the reversal of an accrual for station service obligation by approximately $18 million as a result of a favorable court decision. This was partially offset by higher maintenance expense of approximately $7 million primarily due to additional spending to improve plant reliability as well as $5 million higher property tax expense following the reduction of a property tax credit anticipated from the State of New York. For the second quarter of 2006, G&A expenses were approximately $24 million compared to approximately $27 million in the comparable period of 2005. This decrease was due to a reduction in corporate allocations as a result of the inclusion of NRG Texas to the NRG portfolio.
Year-to-date Results
     Operating Income
     For the six months ended June 30, 2006, operating income for the Northeast region increased by 197% to $217 million compared to the six months ended June 30, 2005. This was primarily driven by net forward MTM impacts, higher capacity revenues, and the sale of SO 2  emission allowances. The Northeast region recorded a net $25 million gain associated with forward sales of electricity as compared to a $33 million loss for the same period in 2005. Increased capacity revenues reflected higher capacity prices for the New York and Connecticutt RMR assets as compared to the first half of 2005. Maintenance expenditures rose by $10 million in the first half of 2006 compared to the first half of 2005 due to additional reliability spending projects at the plants combined with additional outage work at Oswego. Lower generation combined with weaker power prices in the key New York markets in the Northeast region accounted for an 18% decrease in energy revenues for the comparable period. The mild January winter weather in 2006 compared with the cold winter weather in January of 2005 accounted for approximately 60% of the total first half of 2006 variance in generation volumes. Coal-based generation in the first half of 2006 was up 0.3 million MWhrs primarily due to the Indian River and Huntley plants as both plants had outages during the first half of 2005. Other revenues were positively impacted by the sale in emission allowances, which contributed approximately $64 million for the six months ended June 30, 2006.
     Revenues
     Total operating revenues for the Northeast region increased by 7% to $695 million for the six months ended June 30, 2006 compared to $648 million for the six months ended June 30, 2005. Revenues for the six months ended June 30, 2006 included $421 million in energy revenues compared to $513 million for the same period in 2005. Of this $92 million decrease, $61 million and $43 million can be attributed to the Company’s New York and New England assets, respectively. Capacity revenues for the six months ended June 30, 2006 increased by $11 million or 8% to $149 million compared to $138 million for the prior comparable period in 2005. This increase was primarily due to $7 million of additional capacity revenues recorded during the first half of 2006 due to higher approved rates from the Connecticut RMR agreements. In addition, the Northeast region recognized $4 million in higher capacity revenues from the New York plants as in-City prices have been clearing at rates higher than the prior comparable period. Risk management activities included a $25 million gain for the first half of 2005 as compared to a $33 million loss in 2006. Other revenues increased by 112% to $70 million for the first six months of 2006 compared to $33 million for the same period in 2005. During the first half of 2006, the Northeast region realized $64 million in emission allowance sales in lieu of generation compared to $2 million in the first half year of 2005. Expense recoveries related to Connecticut RMR agreements were lower by $5 million over the comparable prior period.
     Cost of Energy
     Cost of energy in the Northeast decreased by 27% or $94 million for the six months ended June 30, 2006 to $249 million compared to the first half of 2005. This was primarily due to lower generation from the New York City and Connecticut plants resulting in lower oil fuel costs of $71 million, while gas costs were $52 million, half as much as in first half of 2005. This was partially offset by higher coal costs to $148 million, an increase of $24 million over the first half 2005 due a combination of higher coal-based generation from the Indian River plant and higher coal prices.
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     Other Operating Expenses
     Other operating expenses for the Northeast region were $185 million for the six months ended June 30, 2006 compared to $195 million for the six months ended June 30, 2005. Maintenance expenditures were $10 million higher than the prior comparable period in 2005 due to additional reliability projects undertaken together with additional outage work at the Oswego plant. Property taxes were $5 million higher than the prior comparable period due to the reduction of property tax credit from the State of New York. These unfavorable variances were more than offset in the first half of 2006 by a net $18 million accrual reversal related to a favorable court decision related to station service obligations at the Western New York plants and a $8 million reduction in corporate allocations as a result of the inclusion of NRG Texas to the NRG portfolio.
South Central Region
     For a discussion of the business profile of the South Central region, see pages 25-27 of NRG Energy Inc’s. 2005 Annual Report on Form 10-K.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Three months ended June 30,	 	 	Six months ended June 30,	 	
 	 	 	 	
(In millions except otherwise noted)	 	2006	 	 	2005	 	 	Change %	 	 	2006	 	 	2005	 	 	Change %	 	
 	
Operating Revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Energy revenue	 	$	52	 	 	$	60	 	 	 	(13	)	 	$	161	 	 	$	129	 	 	 	25	 	
Capacity revenue	 	 	49	 	 	 	46	 	 	 	7	 	 	 	97	 	 	 	91	 	 	 	7	 	
Risk Management Activities	 	 	(1	)	 	 	—	 	 	NA	 	 	 	4	 	 	 	—	 	 	NA	 	
Contract amortization	 	 	4	 	 	 	3	 	 	 	33	 	 	 	8	 	 	 	6	 	 	 	33	 	
Other revenues	 	 	(10	)	 	 	—	 	 	NA	 	 	 	(4	)	 	 	—	 	 	NA	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total operating revenues	 	 	94	 	 	 	109	 	 	 	(14	)	 	 	266	 	 	 	226	 	 	 	18	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Cost of energy	 	 	49	 	 	 	71	 	 	 	(31	)	 	 	139	 	 	 	138	 	 	 	—	 	
Other operating expenses	 	 	26	 	 	 	27	 	 	 	(4	)	 	 	47	 	 	 	51	 	 	 	(8	)	
Depreciation and amortization	 	 	15	 	 	 	15	 	 	 	—	 	 	 	30	 	 	 	30	 	 	 	—	 	
Operating income/(loss)	 	$	4	 	 	$	(4	)	 	NA	 	 	$	50	 	 	$	7	 	 	 	614	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
MWh sold (in thousands)	 	 	2,742	 	 	 	2,225	 	 	 	23	 	 	 	5,987	 	 	 	4,761	 	 	 	26	 	
Business Metrics	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Average on-peak market power prices ($/MWh)	 	 	56.96	 	 	 	57.42	 	 	 	(1	)	 	 	55.51	 	 	 	53.16	 	 	 	4	 	
Cooling Degree Days, or CDDs(a)	 	 	1,012	 	 	 	858	 	 	 	18	 	 	 	1,126	 	 	 	939	 	 	 	20	 	
CDD’s 30 year rolling average	 	 	857	 	 	 	857	 	 	 	—	 	 	 	857	 	 	 	857	 	 	 	—	 	
Heating Degree Days, or HDDs(a)	 	 	47	 	 	 	129	 	 	 	(64	)	 	 	993	 	 	 	1,177	 	 	 	(16	)	
HDD’s 30 year rolling average	 	 	1,382	 	 	 	1,382	 	 	 	—	 	 	 	1,382	 	 	 	1,382	 	 	 	—	 	

(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.	
Quarterly Results
     Operating Income
     For the three months ended June 30, 2006, the South Central region realized operating income of $4 million, compared to an operating loss of $4 million for the three months ended June 30, 2005. Second quarter of 2006 power generation increased by 14% due to lower outage rates. The EFOR rate improved to 6.26% for the second quarter of 2006 compared to an EFOR rate of 10.68% in the second quarter of 2005. This improvement in unit performance and tolling agreements with two third-party facilities created the opportunity for NRG to sell additional MWhs in the higher-margin merchant market in the region.
     Revenues
     Total operating revenues from the South Central region were $94 million for the quarter ended June 30, 2006, a decrease of $15 million or 14% from the second quarter of 2005. Energy revenues for the second quarter 2006 totaled $52 million, of which 100% was contracted. This compares to $60 million of energy revenues for the quarter ended June 30, 2005, of which 78% was contracted. The $8 million decrease in energy revenues and the higher percentage of contracted revenues was due increased trading activity related to purchased electricity that was then resold. EITF 02-3 require that energy purchased for resale be netted on the income statement. The above does not impact gross margin as it reduces both merchant sales revenue and purchased energy costs by $30 million. Other revenues for the second quarter ended June 30, 2006 was a loss of $10 million due to net gas purchases for tolling agreements
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     Cost of Energy
     South Central region’s cost of energy decreased by $22 million for the three months ended June 30, 2006 compared to the same period in 2005. Of this amount, approximately $30 million was due to the impact of net energy purchase and resales as discussed above, partially offset by an $8 million increase in coal costs due to increased generation for the period. The region made extensive use of its tolling agreements in the second quarter of 2006 which significantly reduced the cost of power purchased to support the region’s load contracts. Additionally, during second quarter of 2005, the Big Cajun II facility experienced a number of unplanned outages, requiring the purchase of energy to meet the region’s contract load.
     Other Operating Expenses
     Other operating expenses decreased by $1 million during the second quarter of 2006 compared to the second quarter 2005. Normal maintenance increased by approximately $1 million compared to the second quarter of 2005 due to ongoing reliability improvement initiatives and repair of capital spare. Corporate allocations decreased $2 million in the second quarter of 2006 compared to the second quarter of 2005 as a result of the inclusion of NRG Texas to the NRG portfolio.
Year-to-date Results
     Operating Income
     Operating income for the South Central region was $50 million for the six months ended June 30, 2006 compared to operating income of $7 million for the six months ended June 30, 2005. The availability of the region’s baseload coal plants increased significantly in 2006 compared to 2005. Year-to-date EFOR rates through June 30, 2006 and 2005 were approximately 4% and 8% respectively resulting in a 12% increase in generation in 2006.
     Revenues
     Total operating revenues for the first six months of 2006 were up $40 million or 18% to $266 million compared to $226 million for the six months of 2005. Energy revenues for the six months ended June 30, 2006 were $161 million, while revenues for the same period in 2005 were $129 million an increase of $32 million. This was comprised of an $11 million increase in contract energy revenues primarily due warmer weather and the addition of several new municipalities to the region’s contract load. The additional $21 million increase in merchant energy revenues reflected improved unit availability and increased merchant sales. Capacity revenues for the first six months of 2006 were $97 million, $6 million higher than the same period in 2005. Contract amortization primarily increased by $2 million from the same period in 2005 due to higher contract sales volume. The South Central region earned $4 million in 2006 from its risk management activities.
     Cost of Energy
     South Central region’s cost of energy increased by $1 million for the six months ended June 30, 2006 compared to the same period in 2005. Fuel costs were up by $10 million because of 12% higher generation. The higher fuel costs were offset by a $9 million decrease in purchased power costs as higher plant availability mitigated the need to purchase power to support load contracts.
     Other Operating Expenses
     For the six months ended June 30, 2006, other operating expenses decreased by $4 million from the same period in 2005. Decreases in labor and insurance; of $1 million, and NRG corporate allocations of $4 million were offset by increases of $1 million related to the region’s repowering projects. Corporate allocations decreased by $4 million as a result of the inclusion of NRG Texas to the NRG portfolio.
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Western Region
     For a discussion of the business profile of the Western region, see pages 27-31 of NRG Energy Inc’s. 2005 Annual Report on Form 10-K.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Three months ended June 30,	 	 	Six months ended June 30,	 	
 	 	 	 	
(In millions except otherwise noted)	 	2006	 	 	2005	 	 	Change %	 	 	2006	 	 	2005	 	 	Change	 	
 	
Operating Revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Energy revenue	 	$	27	 	 	$	—	 	 	NA	 	 	$	27	 	 	$	—	 	 	NA	 	
Capacity revenue	 	 	20	 	 	 	—	 	 	NA	 	 	 	20	 	 	 	—	 	 	NA	 	
Risk Management Activities	 	 	(1	)	 	 	—	 	 	NA	 	 	 	(1	)	 	 	—	 	 	NA	 	
Contract amortization	 	 	—	 	 	 	—	 	 	NA	 	 	 	—	 	 	 	—	 	 	NA	 	
Other revenues	 	 	3	 	 	 	—	 	 	NA	 	 	 	3	 	 	 	—	 	 	NA	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total operating revenues	 	 	49	 	 	 	—	 	 	NA	 	 	 	49	 	 	 	—	 	 	NA	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Cost of energy	 	 	26	 	 	 	—	 	 	NA	 	 	 	26	 	 	 	—	 	 	NA	 	
Other operating expenses	 	 	15	 	 	 	2	 	 	NA	 	 	 	17	 	 	 	3	 	 	NA	 	
Depreciation and amortization	 	 	1	 	 	 	—	 	 	NA	 	 	 	1	 	 	 	—	 	 	NA	 	
Operating income/(loss)	 	$	7	 	 	$	(2	)	 	NA	 	 	$	5	 	 	$	(3	)	 	NA	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
MWh sold (in thousands)	 	 	400	 	 	 	449	 	 	 	(11	)	 	 	694	 	 	 	924	 	 	 	(25	)	
Business Metrics	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Average on-peak market power prices ($/MWh)	 	 	47.39	 	 	 	52.87	 	 	 	(10	)	 	 	52.03	 	 	 	53.79	 	 	 	(3	)	
Cooling Degree Days, or CDDs(a)	 	 	240	 	 	 	148	 	 	 	62	 	 	 	240	 	 	 	151	 	 	 	59	 	
CDD’s 30 year rolling average	 	 	157	 	 	 	157	 	 	 	—	 	 	 	157	 	 	 	157	 	 	 	—	 	
Heating Degree Days, or HDDs(a)	 	 	435	 	 	 	475	 	 	 	(8	)	 	 	1,869	 	 	 	1,791	 	 	 	4	 	
HDD’s 30 year rolling average	 	 	1,975	 	 	 	1,975	 	 	 	—	 	 	 	1,975	 	 	 	1,975	 	 	 	—	 	

(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.	
Quarterly and Year-to-date Results
     Operating Income
     With the acquisition of Dynegy’s 50% interest of WCP on March 31, 2006, NRG now consolidates the results of WCP into its financial statements. The quarterly and year-to-date results were primarily due to the impact of the acquisition. Operating income the three and six months ended June 30, 2006 were $7 million and $5 million, respectively.
     Revenues
     Total operating revenues for the Western region were $49 million, which includes $27 million of energy revenues and $20 million of capacity revenues for the three months and six months ended June 30, 2006. Capacity revenues were related to tolling agreements at the El Segundo and Red Bluff, Chow Chilla units and RMR agreements at the Cabrillo I and II plants.
     Risk Management Activity – The total derivative loss for both three and six months ended June 30, 2006 was $1 million, due to mark-to-market losses. The mark-to-market losses represent the change in fair value of forward natural gas purchases related to Saguaro. The Western region did not have any hedge positions in 2005.
     Cost of Energy
     Cost of energy is comprised of $26 million in fuel gas costs for the Western region for the three and six months ended June 30, 2006.
     Other Operating Expenses
     Other operating expenses for Western operations for the three and six months ended June 30, 2006 were $15 million and $17 million, respectively compared to $2 million and $3 million for the three and six months ended June 30, 2005, respectively. The increase in operating expenses was primarily due to the acquisition of Dynegy’s 50% interest in WCP.
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Liquidity and Capital Resources
     Significant Events during the six months ended June 30, 2006
     Acquisitions and Dispositions
 	•	 	The acquisition of Texas Genco LLC	
 	 	 	 	
 	•	 	The purchase of 50% of the interest in WCP and sale of NRG’s 50% interest in Rocky Road for a net $160 million	
 	 	 	 	
 	•	 	Sale of non-core assets resulting in $86 million in proceeds	
     Financings
 	•	 	The issuance of $5.6 billion in a new credit facility, including a $1 billion revolving credit facility and $1 billion synthetic letter of credit facility; $3.6 billion in unsecured high yield notes; $500 million of 5.75% Preferred Stock; and $1 billion of common stock	
 	 	 	 	
 	•	 	The termination of NRG term loan, funded letter of credit and revolving credit facilities issued on December 24, 2004	
 	 	 	 	
 	•	 	The repurchase of $1.1 billion in aggregate principal amount of NRG’s 8% Second Priority Notes	
 	 	 	 	
 	•	 	The repurchase of $1.1 billion in aggregate principal amount of NRG Texas’s and Texas Genco Financing Corp.’s 6.875% senior notes	
 	 	 	 	
 	•	 	The return of cash collateral payments of $272 million due to the downward shift in the underlying price curves	
     Liquidity Position
     As of June 30, 2006, NRG’s liquidity was approximately $2.0 billion and included approximately $1.0 billion of unrestricted and restricted cash. NRG’s liquidity also included $846 million of borrowing capacity under the Company’s revolving line of credit, and $116 million of availability under the Company’s letter of credit facility. As of December 31, 2005, NRG’s liquidity was $730 million and included $542 million of cash and restricted cash. The Company’s liquidity also included $150 million of available capacity under the Company’s revolving line of credit and $38 million of availability under the Company’s letter of credit facility.
     Capital Allocation
     The Company’s stated capital allocation philosophy includes business reinvestment, maintenance of prudent debt levels and interest coverage and the regular return of capital to shareholders. The allocation of capital to any of these areas could have a material affect on the Company’s future liquidity. Further definitions of NRG’s allocation program are provided below.
 	•	 	Business Reinvestment – Opportunities to invest in the existing business, pursue repowering initiatives and expansion projects, or other investments in and or around the existing assets that are projected to provide an economic return to the Company.	
 	 	 	 	
 	•	 	Management of Debt Levels – The Company uses several metrics to measure the efficiency of its capital structure and debt balances. Generally, the Company’s targeted net debt to total capital ratio range is 45% to 60%. The Company intends in the normal course of business continue to manage its debt levels towards the lower end of the range and may, from time to time, pay down its debt balances for a variety of reasons.	
 	 	 	 	
 	•	 	Return of Capital to Shareholders – The Company’s debt instruments include restrictions on the amount of capital that can be returned to shareholders, but the Company has in the past returned capital to shareholders while maintaining compliance with existing debt agreements and indentures. The Company expects to return capital either through dividends or share repurchases.	
     Acquisition of Texas Genco and Related Financing
     On February 2, 2006, NRG acquired Texas Genco LLC, pursuant to an Acquisition Agreement dated September 30, 2005. 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 NRG’s common stock issued to the Sellers was based on the Company’s 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. In connection with the acquisition, NRG substantially revised its financial structure.
     The acquisition of Texas Genco LLC and related financial restructuring was funded with (i) cash proceeds received upon the issuance and sale in a public offering of 20,855,057 shares of NRG 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.
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     On January 31, 2006, NRG used proceeds from the issuance of common stock and cash on hand to repay the $446 million outstanding principal balance of the Company’s senior secured term loan facility, along with accrued but unpaid interest of approximately $2 million and terminated the facility. On February 2, 2006, NRG used proceeds from the new debt financing to pay accrued but unpaid fees on the Company’s revolving credit facility and funded letter of credit facility, and terminated those facilities. Those facilities were replaced by the new term loan, letter of credit and revolving financing facilities as of February 2, 2006.
     NRG’s previously outstanding 8% Second Priority Notes of approximately $1.2 billion were repurchased by NRG on February 2, 2006 and previously outstanding Texas Genco Notes of approximately $1.2 billion were purchased by NRG on February 3, 2006, with proceeds from the issuance of new unsecured high yield notes.
     As of June 30, 2006, NRG had $3.6 billion in aggregate principal amount of unsecured high yield notes or Senior Notes and $3.566 billion in principal amount outstanding under the term loan. NRG has issued $884 million of letters of credit under the Company’s $1.0 billion funded letter of credit facility, leaving $116 million available for future issuances. Under the Company’s $1 billion revolving facility, as of June 30, 2006, NRG had issued $154 million in letters of credit, leaving $846 million available for borrowings, of which approximately $146 million could be used to issue additional letters of credit. As of August 1, 2006, $115 million of undrawn letters of credit remain available under the funded letter of credit facility, $149 million of undrawn letters of credit remain available under the revolving credit facility, and NRG had no borrowings on the Company’s revolving credit facility.
     Collateral
     In connection with the Company’s power generation business, NRG manages the commodity price risk associated with the Company’s supply activities and electric generation facilities. This includes forward power sales, fuel and energy purchases and emission allowances. In order to manage these risks, NRG enters into financial instruments to hedge the variability in future cash flows from forecasted sales of electricity and purchases of fuel and energy. NRG utilizes a variety of instruments including forward contracts, future contracts, swaps and options. Certain of these contracts allow counterparties to require NRG to post margin collateral. As of August 1, 2006, NRG had posted $247 million in collateral to support these contracts.
     In March 2004, NRG entered into two interest rate swap agreements, one of which matured on March 31, 2006. The remaining swap agreement matures in 2011. Depending on market interest rates, NRG or the swap counterparty may be required to post collateral on a daily basis in support of this swap, to the benefit of the other party. On June 30, 2006 and August 1, 2006, NRG had posted approximately $26 million and $20 million, respectively, in collateral.
     Capital Expenditures
     Capital expenditures were approximately $39 million and $26 million for the three months ended June 30, 2006 and 2005, respectively and $74 million and $37 million for the six months ended June 30 2006 and 2005, respectively. The increase in expenditures quarter-over-quarter and year-over-year was due to the acquisition of NRG Texas, which represented half of the capital expenditures year-to-date. NRG anticipates that the Company’s 2006 capital expenditures will be approximately $250 million and will be related to the operation and maintenance of NRG’s existing generating facilities. NRG capital expenditures will be funded through cash from operations.
     Sale or Purchase of Assets
     See Note 3 and Note 5 to the condensed consolidated financial statements of this Form 10-Q for a discussion on the sale and/or purchase of assets.
     NOL’s and Deferred Tax Assets
     As of June 30, 2006 NRG had a U.S. domestic net operating loss carryforward of $381 million which will expire in 2026. NRG believes that it is more likely than not that a benefit will not be realized on the deferred tax assets relating to the net operating loss carryforwards. This assessment included consideration of positive and negative factors, including NRG’s current financial position, results of operations, projected future taxable income, including projected operating and capital gains, and available tax planning strategies. Therefore, as of June 30, 2006, a valuation allowance of $665 million was recorded against the net deferred tax assets. These deferred tax assets are inclusive of amounts created at the acquisition of Texas Genco LLC and net operating loss carryforwards in accordance with FAS 109.
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     Australia
     On June 1, 2006 NRG entered into a sale and purchase agreement to sell its 100% owned Flinders power station and related assets, located near Port Augusta, Australia to Babcock & Brown Power Pty, a subsidiary of Babcock & Brown, a global investment and advisory firm for a purchase price of approximately $231 million (AU$317 million), subject to customary purchase price adjustments, plus the assumption of approximately $174 million (AU$238 million) of non-recourse debt obligations and approximately $31 million (AU$42 million) in cash. NRG anticipates closing the transaction during the fourth quarter of 2006.
     On June 8, 2006 NRG also announced the sale of the Company’s 37.5% equity interest in the Gladstone power station, and its associated 100% owned NRG Gladstone Operating Services company, to Transfield Services, an Australia-based provider of operations, maintenance, ownership and asset management services for a purchase price of approximately $174 million (AU$239 million) subject to customary purchase price adjustments, plus assumption of NRG’s share of Gladstone’s unconsolidated debt and cash amounting to approximately $56 million (AU$ 77 million) and approximately $26 million (AU$35 million), respectively. After tax cash proceeds are expected to be in excess of approximately $171 million (AU$ 234 million). NRG is seeking to close the transaction during the fourth quarter of 2006, but considerable uncertainty remains over NRG’s ability to satisfy certain conditions particularly the securing of certain consents and waivers from the other owners of the project.
     Share Repurchase
     On August 1, 2006, NRG Energy, Inc., announced a $750 million share repurchase program to be implemented in two phases. Phase I is a $500 million common stock repurchase program that the Company intends to commence in August 2006 and to complete by year end 2006. Phase II of the share repurchase plan is expected to be an additional $250 million common stock buyback to be commenced at or near the end of the first quarter of 2007, however the Company may reallocate all or a portion of Phase II to the initiation of a common stock dividend.
     The Company formed two wholly-owned special purpose subsidiaries which will repurchase the shares in Phase I. The Company will capitalize the subsidiaries with $166 million in cash. Additionally, the subsidiaries will enter into non-recourse facilities with units of Credit Suisse for a total of $334 million, consisting of $250 million in debt and the issuance by the subsidiaries of $84 million of preferred equity. Neither the debt nor the preferred will be recourse to the Company. The $500 million of NRG common stock, which the subsidiaries are expected to purchase between now and year end 2006, will serve as collateral for the debt. Funding for the share repurchases will be drawn pro rata from the $166 million in cash provided by the Company and the $334 million in debt and preferred financings from Credit Suisse. The debt and preferred of one of the subsidiaries, of approximately $190 million, is expected to mature in the fourth quarter of 2008, and the debt and preferred of the second subsidiary, of approximately $144 million, is expected to mature in the fourth quarter of 2009. The debt will accrue interest and the preferred will accrue dividends which will be paid at maturity, with the accrued interest and dividends for both subsidiaries totaling approximately $66 million. In addition, Credit Suisse will retain the economic benefit of share price appreciation in excess of a 20 percent compound annual growth rate.
     Repowering Initiative
     On June 21, 2006, NRG announced a comprehensive portfolio redevelopment effort, which involves the development, financing, construction and operation of up to 10,500 megawatts of new multi-fuel, multi-technology generation capacity at NRG’s existing domestic sites to meet the growing demand for principally non gas-fired generation in all of the Company’s core domestic markets.
Cash Flow Discussion
 	 	 	 	 	 	 	 	 	 	
 	 	Six months ended June 30,	 	 	
(In millions)	 	2006	 	 	2005	 	 	
Net cash provided by operating activities	 	$	604	 	 	$	91	 	 	
Net cash provided by investing activities	 	 	(4,292	)	 	 	148	 	 	
Net cash used in financing activities	 	$	4,148	 	 	$	(527	)	 	
 	 	 	 	 	 	 	
     Net Cash Provided By Operating Activities
     For the six months ended June 30, 2006, net cash provided by operating activities increased by $513 million compared to the same period in 2005. This was primarily due to the following reasons:
 	•	 	Due to expiration of the underlying contracts and the downward shift of the forward price curves, NRG’s collateral deposits in support of derivative contracts decreased by $272 million during the six months ended June 30, 2006, compared to an increase of $179 million during the same period of 2005, a difference of $451 million. As of June 30, 2006 NRG had collateral deposits of $209 million;	
 	 	 	 	
 	•	 	Due to the redemption of NRG’s previous senior notes, a premium of $126 million was paid to NRG’s former debt holders;	
 	 	 	 	
 	•	 	NRG’s activity for the period resulted in an increase of $114 million in working capital compared to an increase in working capital for the same period in 2005 of $41 million, a difference of $73 million;	
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 	•	 	Due to redemption of NRG’s 8% Second Priority Notes, during the six months ended June 30, 2006, we wrote off $61 million of deferred financing costs less debt premium of $14 million for a net write-off of $47 million, compared to a write-off of debt premiums of $8 million during the same period in 2005, a difference of $55 million; and	
 	 	 	 	
 	•	 	A gain on the sale of emission allowances adjusted net income by $67 million to reflect the activity as investing. Due to price conditions, it was economically beneficial to sell emissions rather than operate certain plants.	
     Net Cash Provided/(Used) By Investing Activities
     For the six months ended June 30, 2006, net cash used in investing activities was approximately $4.4 billion more than the same period in 2005. NRG’s use of cash was due to the following mix of investment activities:
 	•	 	During the first quarter of 2006, NRG acquired Texas Genco LLC for approximately $6.2 billion (net of assumed debt), which included the issuance of stock at a value of $1.7 billion and a net cash payment of approximately $4.3 billion (net of cash on hand at NRG Texas hand of $238 million);	
 	 	 	 	
 	•	 	NRG acquired Dynegy’s 50% ownership interest in WCP for $25 million (net of cash on hand at WCP hand of $180 million). Prior to the purchase, NRG had an existing investment in WCP accounted for as an unconsolidated equity method investment;	
 	 	 	 	
 	•	 	As disclosed in Note 5 to the condensed consolidated financial statements of this Form 10-Q, NRG divested a number of its equity investments for total proceeds of $86 million;	
 	 	 	 	
 	•	 	NRG’s capital expenditures were $37 million more during the six months ended June 30, 2006 compared to the same period in 2005, with the increase primarily related to the capital expenditures at NRG Texas; and	
 	 	 	 	
 	•	 	During the six months ended June 30, 2005, NRG received $71 million related to the TermoRio settlement	
     Net Cash Provided(Used) in Financing Activities
     For the six months ended June 30, 2006, net cash provided by financing activities increased by approximately $4.7 billion in comparison to same period in 2005. The increase was due primarily to the financing activities surrounding the purchase of NRG Texas, and consisted of the following:
 	•	 	In conjunction with the purchase of NRG Texas, NRG refinanced its outstanding debt as well as NRG Texas’s outstanding debt as the Company:	

 	o	 	Repaid $446 million in outstanding principal and terminated its term loan under NRG’s Amended Credit Facility;	
 	 	 	 	
 	o	 	Repurchased and retired approximately $1.1 billion of NRG’s 8% Second Priority Notes, pursuant to a tender offer; and	
 	 	 	 	
 	o	 	Repurchased NRG Texas’s outstanding notes for approximately $1.1 billion and NRG Texas’s term loan for approximately $500 million.	

•	 	As part of raising the funds to purchase NRG Texas and to refinance the combined NRG debt portfolio, the company:	

 	o	 	Issued 20,855,057 shares of common stock on January 31, 2006 at an offering price of $48.75 per share for total net proceeds of approximately $985 million, after deducting expenses;	
 	 	 	 	
 	o	 	Issued 2 million shares of 5.75% Preferred Stock on January 30, 2006 at an offering price of $250 per share for total net proceeds of approximately $486 million, after deducting expenses;	
 	 	 	 	
 	o	 	Entered into a new senior secured credit facility providing for up to an aggregate amount of $5.575 billion, consisting of a $3.575 billion Term Loan Facility, a $1.0 billion Revolving Credit Facility and a $1.0 billion Letter of Credit Facility; and	
 	 	 	 	
 	o	 	Issued (i) $1.2 billion aggregate principal amount of 7.25% Senior Notes, and (ii) $2.4 billion aggregate principal amount of 7.375% Senior Notes.	

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Off-Balance Sheet Arrangements
     Obligations Under Certain Guarantee Contracts
     NRG and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include financial and performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. See Note 15 to the condensed consolidated financial statements of this Form 10-Q for further details of the guarantee arrangements.
     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 the 3.625% Preferred Stock that includes a conversion feature which was considered a derivative per FAS 133. Although it is considered a derivative, it was exempt from derivative accounting as it was excluded from the scope pursuant to paragraph 11(a) of FAS 133. Despite this exclusion, per the guidance of EITF Topic D-98 the conversion feature must be marked-to-market. Currently, the conversion feature is valued at $0 as NRG’s stock price is outside the conversion range.
     Obligations Arising Out of a Variable Interest in an Unconsolidated Entity
     Variable interest in Equity investments — As of June 30, 2005, 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 $178 million as of June 30, 2006. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to us. In the normal course of business the Company may be asked to loan funds to unconsolidated affiliates on both a long and short-term basis. Such transactions are generally accounted for as accounts payable and receivable to/from affiliates and notes payable/receivable to/from affiliates and if appropriate, bear market-based interest rates.
     New Synthetic Letter of Credit Facility and Revolver Facility — Under the New Senior Credit Facility NRG entered into on February 2, 2006, the Company has a $1 billion synthetic Letter of Credit Facility, and a $1 billion senior Revolving Credit Facility. The synthetic Letter of Credit Facility was secured by a $1 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 is permitted to issue up to $300 million in unfunded letters of credit under the Company’s Revolving Credit Facility, or revolver letters of credit, for ongoing working capital requirements and for general corporate purposes, including acquisitions that are permitted under the New Senior Credit Facility.
     As of June 30, 2006, the Company had issued $884 million in funded letters of credit under the Letter of Credit Facility. Of this amount, a portion was issued to support obligations under terminated NRG letter of credit facilities. As of June 30, 2006, the Company had issued $154 million in revolver letters of credit, a portion of which supports non-commercial letter of credit obligations under letter of credit facilities terminated as of February 2, 2006.
     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, 2005.
     See Note 15 to the condensed consolidated financial statements of this Form 10-Q for a discussion of commitments and contingencies that also include contractual obligations and commercial commitments that occurred during 2006.
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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 impact 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 case, actual results may differ significantly 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.
     Goodwill and Other Intangible Assets
     As part of the acquisition of Texas Genco LLC NRG has recorded intangible assets and goodwill. The Company applied SFAS 141-  Business Combinations  and SFAS 142 —  Goodwill and Other Intangible Assets , to account for these intangibles. Under these standards the Company amortizes all finite-lived intangible assets over their respective estimated weighted-average useful life, whereas goodwill has an indefinite life and is not amortized. However, goodwill and all intangible assets will be tested for impairment whenever an event occurs that indicates that an impairment may have occurred, or at a minimum on an annual basis. If necessary, the Company’s goodwill and/or intangible asset will be impaired at that time.
     In connection with the said acquisition, the Company recognized the estimated fair value of certain power sale contracts and fuel contracts acquired. NRG estimated their fair value using forward pricing curves as of the closing date of the acquisition over the life of each contract. These contracts had negative fair values at the closing date of the acquisition and will be reflected as assumed contracts in the combined balance sheet. Assumed contracts are amortized to revenues and fuel expense as applicable based on the estimated realization of the preliminary fair value established on the closing date over the contractual lives.
     The amount of goodwill as disclosed in the past has decreased due to a change in several factors since the previously reported values. These factors include:
 	•	 	Earlier estimates reported were based on estimated working capital and estimated common stock prices;	
 	 	 	 	
 	•	 	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, NRG has valued goodwill on a preliminary basis at approximately $1.5 billion. NRG’s preliminary appraisal of Property, Plant and Equipment increased its fair value, compared to Texas Genco LLC’s historical cost, by approximately $5.7 billion. If the remaining goodwill balance is indicative of a further increase in value of depreciable property plant and equipment, depreciation expense for the three and six month period ended June 30, 2006, would increase by approximately $21 million and $35 million, respectively, reducing income from continuing operations before tax to a loss for the three and six month period ended June 30, 2006 of approximately $273 million and $275 million, respectively.
     See Note 1 to the condensed consolidated financial statements, to this Form 10-Q for details of changes in accounting standards.
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Item 3 — Quantitative and Qualitative Disclosures About Market Risk
     NRG is exposed to several market risks in the Company’s normal business activities. Market risk is the potential loss that may result from market changes associated with the Company’s merchant power generation or with an existing or forecasted financial or commodity transaction. The types of market risks the Company is exposed to are commodity price risk, interest rate risk and currency exchange risk. In order to manage these risks the Company utilizes various fixed-price forward purchase and sales contracts, futures and option contracts traded on the New York Mercantile Exchange, and swaps and options traded in the over-the-counter financial markets to:
 	•	 	Manage and hedge fixed-price purchase and sales commitments;	
 	 	 	 	
 	•	 	Manage and hedge exposure to variable rate debt obligations;	
 	 	 	 	
 	•	 	Reduce exposure to the volatility of cash market prices; and	
 	 	 	 	
 	•	 	Hedge fuel requirements for the Company’s generating facilities.	
Commodity Price Risk
     Commodity price risks result from exposures to changes in spot prices, forward prices, volatilities 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 the 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, operational, 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. Value-at-risk, or VAR, is a statistical model that attempts to predict risk of loss based on market price volatility. The Company calculates VAR using a variance/covariance technique that models positions using a linear approximation of their value. NRG’s VAR calculation includes mark-to-market and non mark-to-market energy assets and liabilities.
     NRG utilizes a diversified VAR model to calculate the estimate of potential loss in the fair value of the Company’s energy assets and liabilities including 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.
     This model encompasses all of NRG’s generating assets across the entire portfolio including NRG Texas. As of June 30, 2006 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 $53 million.
     In order to provide additional information for comparative purposes to NRG’s peers the Company also utilizes VAR to model the estimate of potential loss of financial derivative instruments included in derivative instruments valuation of assets and liabilities. This estimation includes those energy contracts accounted for as a hedge under SFAS No. 133, as amended. The VAR for the financial derivative instruments calculated using the diversified VAR model as of June 30, 2006 was $35.5 million.
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     With the addition of the NRG Texas portfolio occurring late in the second quarter of 2006, the following table summarizes average VAR for NRG excluding NRG Texas:
 	 	 	 	 	 	 	 	 	
VAR	 	In millions	 	 	 	 	
As of June 30, 2006	 	$	34.8	 	 	 	 	 	
Average for the three months ended June 30, 2006	 	 	32.2	 	 	 	 	 	
Maximum	 	 	35.0	 	 	 	 	 	
Minimum	 	 	28.4	 	 	 	 	 	
 	 	 	 	 	 	 	
As of March 31, 2006	 	$	29.6	 	 	 	 	 	
Average for the three months ended March 31, 2006	 	 	32.7	 	 	 	 	 	
Maximum	 	 	38.0	 	 	 	 	 	
Minimum	 	 	26.8	 	 	 	 	 	
 	 	 	 	 	 	 	
     NRG expects to completely integrate the NRG Texas’ portfolio and begin reporting average, maximum and minimum VAR data by the end of the third quarter of 2006.
     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. Additionally, actual changes in the value of options may differ from the VAR calculated using a linear approximation inherent in the Company’s calculation method. 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.
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 policy allows 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 May 3, 2006 was $2.15 billion. The notional amounts and maturities of each tranche of these swaps are described in Note 8 to the condensed consolidated financial statements of this Form 10-Q.
     As of June 30, 2006, the Company had various interest rate swap agreements with notional amounts totaling approximately $2.8 billion. If the swaps had been discontinued on June 30, 2006, the Company would have owed the counter-parties approximately $28.6 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 June 30, 2006, a 100 basis point change in interest rates would result in a $18.5 million change in interest expense on a rolling twelve month basis.
     At June 30, 2006, the fair value of the Company’s long-term debt was $7.7 billion, compared to the carrying amount of $7.8 billion. NRG estimates that a 1% decrease in market interest rates would have increased the fair value of the Company’s long-term debt by $427 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
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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 believes it to be appropriate.
     In connection with the sale of Flinders as discussed in Note 3 to the condensed consolidated financial statements to this Form 10-Q, NRG purchased an option to protect against any negative adverse affects from the exchange rate related to the proceeds from the sale. As of June 30, 2006, the results of any outstanding foreign currency exchange contracts were immaterial to NRG’s financial results.
Liquidity Risk
     Liquidity risk arises from the general funding needs of the Company’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.
     NRG’s collateral posted in support of the management of NRG’s electric generation facilities fluctuates based on the amount of the portfolio hedged using collateralized contracts and market price movements. Based on a sensitivity analysis a $1 per MWh increase or decrease in electricity prices would cause a change in margin collateral outstanding of approximately $23 million as of June 30, 2006. This sensitivity uses simplified assumptions and may not reflect actual market movements.
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 June 30, 2006, NRG held collateral support of approximately $410 million from counterparties.
     A portion of the NRG’s credit risk is related to transactions that are recorded in the Company’s consolidated Balance Sheets. 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 June 30, 2006:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Exposure	 	 	 	 	 	 	 	 	
 	 	Before	 	 	 	 	 	 	Net	 	
Credit Exposure (In millions, except ratios)	 	Collateral	 	 	Collateral	 	 	Exposure	 	
Investment grade	 	$	987	 	 	$	342	 	 	$	645	 	
Non-investment grade	 	 	56	 	 	 	66	 	 	 	—	 	
Not rated	 	 	149	 	 	 	23	 	 	 	126	 	
 	 	 	 	 	 	 	 	 	 	
Total	 	$	1,192	 	 	$	431	 	 	$	771	 	
 	 	 	 	 	 	 	 	 	 	
Investment grade	 	 	83	%	 	 	79	%	 	 	84	%	
Non-investment grade	 	 	5	%	 	 	15	%	 	 	—	 	
Not rated	 	 	12	%	 	 	6	%	 	 	16	%	
 	 	 	 	 	 	 	 	 	 	
     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 $771 million was approximately $533 million as of June 30, 2006. 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.
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Fair Value of Derivative Instruments
     As the Company engages principally in the trading and marketing of its generation assets, most of the Company’s commercial activities qualify for hedge accounting under the requirements of SFAS No.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 NRG’s 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 the fair value is likely to be reflected on a mark-to-market basis in the statement of operations. The majority of trades in support of NRG’s 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 other comprehensive income.
     As part of the trading and marketing of NRG’s generation assets, the Company may enter into forward power sales contracts, forward gas purchase contracts and other energy related commodities financial instruments to mitigate variability in earnings due to fluctuations in spot market prices, hedge fuel requirements at generation facilities and protect fuel inventories. In addition, in order to mitigate interest rate risk associated with the issuance of NRG’s variable rate and fixed rate debt, the Company enters into interest rate swap agreements.
     The tables below disclose the derivative 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 as at June 30, 2006 based on whether fair values are determined by quoted market prices or more subjective means; and indicate the maturities of contracts at June 30, 2006.
 	 	 	 	 	 	
Derivative Activity Gains/(Losses)	 	(In millions)	 	
 	 	 	
Fair value of contracts at December 31, 2005	 	$	(403	)	 	
Value of Flinders contracts as at December 31, 2005, included in discontinued operations	 	 	72	 	 	
Value of contracts acquired with NRG Texas on February 2, 2006	 	 	(472	)	 	
Contracts realized or otherwise settled during the period	 	 	188	 	 	
Changes in fair value	 	 	296	 	 	
 	 	 	
Fair value of contracts at June 30, 2006	 	$	(319	)	 	

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Fair Value of Contracts as of June 30, 2006	 	
 	 	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	 	$	(124	)	 	$	(186	)	 	$	(26	)	 	$	—	 	 	$	(336	)	
Prices based on models and other valuation methods	 	 	11	 	 	 	(14	)	 	 	50	 	 	 	(30	)	 	 	17	 	
Prices provided by other external sources	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	
Total	 	$	(113	)	 	$	(200	)	 	$	24	 	 	$	(30	)	 	$	(319	)	
 	 	
     NRG may use a variety of financial instruments to manage the Company’s exposure to fluctuations in foreign currency exchange rates on NRG’s international project cash flows, interest rates on the Company’s cost of borrowing and energy and energy related commodities prices.
Item 4 — Controls and Procedures
     Under the supervision and with the participation of NRG’s management, including the Company’s 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 in Rule 13a-15(e) of 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 are effective to ensure that the information required to be disclosed in reports filed under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.
     Except for the completion of the acquisition of Texas Genco LLC and WCP, and the commencement of the associated integration of these entities, there have been no changes in the Company’s internal control over financial reporting during the completed second quarter of 2006 that have materially affected, or are reasonably likely to materially affect the Company’s internal control over financial reporting. NRG previously owned a 50% equity interest in WCP and acquired the remaining interest in WCP with this acquisition.
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PART II — OTHER INFORMATION
Item 1 — Legal Proceedings
     For a discussion of material legal proceedings in which NRG was involved through June 30, 2006, see Note 15 to the condensed consolidated financial statements of this Form 10-Q.
Item 1A. — Risk Factors
     Information regarding risk factors appears in Item 1A Risk Factors in our Annual Report on Form 10-K for the fiscal year ended December 31, 2005. There have been no material changes from the risk factors previously disclosed in our Annual Report on Form 10-K.
Item 2 — Unregistered Sales of Equity Securities and Use of Proceeds
     None.
Item 3 — Defaults Upon Senior Securities
     None.
Item 4 — Submission of Matters to a Vote of Security Holders
     The stockholders of NRG Energy, Inc. voted on four items at the Annual Meeting of Stockholders held on April 28, 2006:
 	1.	 	The election of Class III Directors to a three-year term.	
 	 	 	 	
 	2.	 	The proposal to approve an amendment to Article Four, Section 2 of the Amended and Restated Certification of Incorporation revising the authority of the Board of Directors to issue and designate preferred stock.	
 	 	 	 	
 	3.	 	The proposal to approve an amendment to NRG’s Long-Term Incentive Plan which increases the number of shares available under the plan from 4,000,000 to 8,000,000 shares.	
 	 	 	 	
 	4.	 	The proposal to ratify the appointment of KPMG LLP as NRG’s independent registered public accounting firm.	
     There were 136,975,275 shares of common and preferred stock entitled to vote at the meeting and a total of 116,052,607 shares (84.73%) were represented at the meeting.
     The four individuals named below were elected to serve a three-year term as Class III Directors expiring at the annual meeting of stockholders in 2009:
 	 	 	 	 	 	 	 	 	
Nominee	 	Votes For	 	 	Votes Withheld	 	
 	 	
John F. Chlebowski	 	 	115,576,078	 	 	 	476,529	 	
Howard E. Cosgrove	 	 	115,573,627	 	 	 	478,980	 	
William E. Hantke	 	 	115,574,559	 	 	 	478,048	 	
Anne C. Schaumburg	 	 	115,575,978	 	 	 	476,629	 	
     The names of the directors whose terms of office as directors continued after the meeting are as follows:
     Class I: David Crane, Stephen L. Cropper, Maureen Miskovic and Thomas Weidemeyer
     Class II: Lawrence S. Coben, Paul W. Hobby, Herbert H. Tate and Walter R. Young
     The proposal to approve the amendment to Article Four, Section 2 of the Amended and Restated Certificate of Incorporation was not approved with 46,776,674 shares voting for, 43,593,050 shares voting against, 132,189 shares abstaining and 25,550,694 broker non-votes.
     The proposal to approve the amendment to NRG’s Long-Term Incentive Plan was approved with 51,835,398 shares voting for, 38,556,104 shares voting against, 110,411 shares abstaining and 25,550,694 broker non-votes.
     The proposal to ratify the appointment of KPMG LLP as independent registered public accounting firm was ratified with 113,902,221 shares voting for, 2,146,691 shares voting against, 3,695 shares abstaining and zero broker non-votes.
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Item 5 — Other Information
     NRG has changed the date of its 2007 Annual Meeting of Stockholders from April 27, 2007, as set forth in its Proxy Statement filed March 20, 2006, to April 25, 2007.
     On May 24, 2006, NRG announced the appointment of The Bank of New York to serve as the Company’s new transfer agent and registrar for the Company’s common stock and preferred stock, effective May 30, 2006 to replace Wells Fargo Shareowner Services.
Item 6 — Exhibits
(a) Exhibits
 	 	 	
4.1	 	Fifth Supplemental Indenture, dated April 28, 2006, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York, incorporated herein by reference to NRG Energy Inc.’s current report on Form 8-K filed on May 3, 2006.	
 	 	 	
4.2	 	Sixth Supplemental Indenture, dated April 28, 2006, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York, incorporated herein by reference to NRG Energy Inc.’s current report on Form 8-K filed on May 3, 2006.	
 	 	 	
4.3	 	Form of NRG Energy, Inc. Common Stock Certificate, filed herewith.	
 	 	 	
10.1	 	NRG Energy, Inc. Long-Term Incentive Plan, as amended, incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on May 4, 2006.	
 	 	 	
10.2	 	NRG Energy, Inc. Director Compensation Table, incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on May 4, 2006.	
 	 	 	
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.	
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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 CRANE	 	 	
 	 	 	 	 	
 	 	David Crane,	 	 	
 	 	Chief Executive Officer	 	 	
 	 	 	 	 	
 	 	/s/ ROBERT C. FLEXON	 	 	
 	 	 	 	 	
 	 	Robert C. Flexon,	 	 	
 	 	Chief Financial Officer	 	 	
 	 	(Principal Financial Officer)	 	 	
 	 	 	 	 	
 	 	/s/ JAMES J. INGOLDSBY	 	 	
 	 	 	 	 	
 	 	James J. Ingoldsby,	 	 	
 	 	Controller	 	 	
 	 	(Principal Accounting Officer)	 	 	
Date: August 4, 2006
76

Table of Contents
Exhibit Index
 	 	 	
4.1	 	Fifth Supplemental Indenture, dated April 28, 2006, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York, incorporated herein by reference to NRG Energy Inc.’s current report on Form 8-K filed on May 3, 2006.	
 	 	 	
4.2	 	Sixth Supplemental Indenture, dated April 28, 2006, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York, incorporated herein by reference to NRG Energy Inc.’s current report on Form 8-K filed on May 3, 2006.	
 	 	 	
4.3	 	Form of NRG Energy, Inc. Common Stock Certificate, filed herewith.	
 	 	 	
10.1	 	NRG Energy, Inc. Long-Term Incentive Plan, as amended, incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on May 4, 2006.	
 	 	 	
10.2	 	NRG Energy, Inc. Director Compensation Table, incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on May 4, 2006.	
 	 	 	
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.	
77

 

stock certificate
cusip 629377 50 8	

 

 
EXHIBIT 31.1
CERTIFICATION
I, David Crane, certify that:
      1. I have reviewed this quarterly report on Form 10-Q of NRG Energy, Inc.;
      2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
      3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
      4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
      (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under the Company’s supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
      (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under the Company’s supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
      (c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report the Company’s conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
      (d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
      5. The registrant’s other certifying officers and I have disclosed, based on the Company’s most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
      (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
      (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

 	/s/ DAVID CRANE  	 	
 	David Crane 	 	
 	Chief Executive Officer
(Principal Executive Officer)  	 	
 	
Date: August 4, 2006
78

 
EXHIBIT 31.2
CERTIFICATION
I, Robert C. Flexon, certify that:
     1.  I have reviewed this quarterly report on Form 10-Q of NRG Energy, Inc.;
     2.  Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
     3.  Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
     4.  The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
     (a)  Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under the Company’s supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
     (b)  Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under the Company’s supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
     (c)  Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report the Company’s conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
     (d)  Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
     5.   The registrant’s other certifying officers and I have disclosed, based on the Company’s most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
     (a)  All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
     (b)  Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

 	/s/ ROBERT C. FLEXON  	 	
 	Robert C. Flexon 	 	
 	Chief Financial Officer
(Principal Financial Officer)  	 	
 	
     Date: August 4, 2006
79

 
EXHIBIT 31.3
CERTIFICATION
I, James J. Ingoldsby, certify that:
 	1.	 	I have reviewed this quarterly report on Form 10-Q of NRG Energy, Inc.;	
      2.     Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
      3.     Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
      4.     The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
      (a)  Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under the Company’s supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
      (b)   Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under the Company’s supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
      (c)   Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report the Company’s conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
      (d)   Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.   The registrant’s other certifying officers and I have disclosed, based on the Company’s most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):	
      (a)  All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
      (b)  Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

 	/s/ JAMES J. INGOLDSBY  	 	
 	James J. Ingoldsby 	 	
 	Controller
(Principal Accounting Officer)  	 	
 	
Date: August 4, 2006
80

 
EXHIBIT 32
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
     In connection with the Quarterly Report of NRG Energy, Inc. on Form 10-Q for the quarter ended June 30, 2006, as filed with the Securities and Exchange Commission on the date hereof (Form 10-Q), each of the undersigned officers of the Company certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge:
     (1) The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
     (2) The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company as of the dates and for the periods expressed in the Form 10-Q.
Date: August 4, 2006
 	 	 	 	 	
 	 	/s/ DAVID CRANE
 	 	 	
 	 	David Crane,	 	 	
 	 	Chief Executive Officer	 	 	
 	 	(Principal Executive Officer)	 	 	
 	 	 	 	 	
 	 	/s/ ROBERT C. FLEXON	 	 	
 	 	 	 	 	
 	 	Robert C. Flexon,	 	 	
 	 	Chief Financial Officer	 	 	
 	 	(Principal Financial Officer)	 	 	
 	 	 	 	 	
 	 	/s/ JAMES J. INGOLDSBY	 	 	
 	 	 	 	 	
 	 	James J. Ingoldsby,	 	 	
 	 	Controller	 	 	
 	 	(Principal Accounting Officer)	 	 	
     The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.
     A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to NRG Energy, Inc. and will be retained by NRG Energy, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.
81