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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K/A
Amendment No. 2
 	 	 	
[X]	 	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934	
 	 	 	
 	 	For the Fiscal Year ended December 31, 2003.	
 	 	 	
[  ]	 	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934	
 	 	For the Transition Period from           to       .	
Commission File No. 001-15891

NRG Energy, Inc.
(Exact name of Registrant as specified in its charter)
 	 	 	 	 	
Delaware	 	 	41-1724239	 	
(State or other jurisdiction of	 	(I.R.S. Employer	
incorporation or organization)	 	Identification No.)	
901 Marquette Avenue	 	 	 	 	
Minneapolis, Minnesota	 	 	55402	 	
(Address of principal executive offices)	 	(Zip Code)	
(612) 373-5300
(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:
 	 	 	
Title of Each Class	 	Name of Exchange on Which Registered	

 	 	

 	
None	 	None	
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, par value $0.01 per share

     Indicate by check mark whether the Registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [   ]

     Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [   ]

     Indicate by check mark whether the registrant is an accelerated filer as defined by Rule 12b-2 of the Act. Yes [X] No [   ]

     As of the last business day of the most recently completed second fiscal quarter, the aggregate market value of the common stock of the registrant held by non-affiliates was approximately $1,943,806,466.

     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 Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes [X] No [   ]

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     Indicate the number of shares outstanding of each of the registrant’s classes of common stock as of the latest practicable date.
 	 	 	
Class	 	Outstanding at October 29, 2004	

	 	

	
Common Stock, par value $0.01 per share	 	100,008,053	
Documents Incorporated by Reference:
None

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NRG ENERGY, INC. AND SUBSIDIARIES

INDEX
 	 	 	 	 	 	 	 	 	
 	 	 	 	Page No.

	 	 	 	 	
 	 	PART II	 	 	 	 	 	 	
Item 6	 	Selected Financial Data	 	4	 	 	 	 	
Item 7	 	Management’s Discussion and Analysis of Financial Condition and Results of Operations	 	5	 	 	 	 	
 	 	PART IV	 	 	 	 	 	 	
Item 15	 	Exhibits, Financial Statements Schedules and Reports on Form 8-K	 	33	 	 	 	 	
Signatures	 	 	 	145	 	 	 	 	
 Registration Rights Agreement	
 Consent of PricewaterhouseCoopers LLP	
 Certification of David Crane	
 Certification of Robert Flexon	
 Certification of James Ingoldsby	
 Section 1350 Certification	
 Financial Statements/Louisiana Generating LLC	
 Financial Statements/NRG Northeast Generating	
 Financial Statements/Indian River Power LLC	
 Financial Statements/NRG Mid-Atlantic Generating	
 Financial Statements/NRG South Central Generating	
 Financial Statements/NRG Eastern LLC	
 Financial Statements/NRG Northeast Generation	
 Financial Statements/NRG International LLC	

In connection with the upcoming registration of our 8% Second Priority Senior Notes due December 15, 2013 issued on December 17, 2003 and January 28, 2004, we are reissuing our audited financial statements for the year ended December 31, 2003 as Amendment No. 2 on Form 10-K/A. The updated information includes 2004 discontinued operations as described in Note 6 and consolidating financial statements as required by Rule 3-10 of Regulation S-X as described in Note 30. Discontinued operations have been updated to include the addition of entities related to the sale of our interests in Penobscot Energy Recovery Company, Compania Boliviana De Energia Electrica S.A. – Bolivian Power Company Limited, LSP Energy and Hsin Yu. Our segment reporting disclosures, as shown in Note 20, have been restated to be consistent with the realignment of our management team and our segment disclosures included in our quarterly financials included in our Form 10-Q for the quarter ended June 30, 2004, filed on August 9, 2004. In addition, we have attached to this Form 10-K/A exhibits 99.2 through 99.9, the audited financial statements of eight significant guarantor subsidiaries as required by Rule 3-16 of Regulation S-X.

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Item 6 — Selected Financial Data

     The following table presents our selected financial data. The data included in the following table has been restated to reflect the assets, liabilities and results of operations of certain projects that have met the criteria for treatment as discontinued operations. For additional information refer to Item 15 — Note 6 to the Consolidated Financial Statements. This historical data should be read in conjunction with the Consolidated Financial Statements and the related notes thereto in Item 15 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7. Due to the adoption of Fresh Start reporting as of December 5, 2003, the Successor Company’s post Fresh Start balance sheet and statement of operations have not been prepared on a consistent basis with the Predecessor Company’s financial statements and are not comparable in certain respects to the financial statements prior to the application of Fresh Start reporting. A black line has been drawn to separate and distinguish between Reorganized NRG and the Predecessor Company.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Reorganized	
 	 	Predecessor Company

	 	NRG

	
 	 	Year Ended December 31,	 	January 1 -	 	December 6 -	

	 	December 5,	 	December 31,	
 	 	1999

	 	2000

	 	2001

	 	2002

	 	2003

	 	2003

	
 	 	 	 	 	 	(In thousands, except per share amounts)	 	 	 	 	
Revenues from majority- owned operations	 	$	418,888	 	 	$	1,665,257	 	 	$	2,085,597	 	 	$	1,938,549	 	 	$	1,798,614	 	 	$	138,507	 	
Legal settlement	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	462,631	 	 	 	—	 	
Fresh start reporting Adjustments	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(4,118,636	)	 	 	—	 	
Reorganization, restructuring and impairment charges	 	 	—	 	 	 	—	 	 	 	—	 	 	 	2,563,060	 	 	 	435,400	 	 	 	2,461	 	
Total operating costs and Expenses	 	 	371,104	 	 	 	1,311,219	 	 	 	1,706,478	 	 	 	4,324,386	 	 	 	(1,473,481	)	 	 	122,412	 	
Write downs and losses on equity method investments	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(200,472	)	 	 	(147,124	)	 	 	—	 	
Income/(loss) from continuing operations	 	 	53,457	 	 	 	149,665	 	 	 	210,049	 	 	 	(2,791,200	)	 	 	2,947,262	 	 	 	11,337	 	
Income/(loss) from discontinued operations, net	 	 	3,738	 	 	 	33,270	 	 	 	55,155	 	 	 	(673,082	)	 	 	(180,817	)	 	 	(312	) 	
Net income/(loss)	 	 	57,195	 	 	 	182,935	 	 	 	265,204	 	 	 	(3,464,282	)	 	 	2,766,445	 	 	 	11,025	 	
Net income per weighted Average share — basic	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	$	.11	 	
Net income per weighted Average share — diluted	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	$	.11	 	
Total assets	 	 	3,435,304	 	 	 	5,978,992	 	 	 	12,922,385	 	 	 	10,896,851	 	 	 	N/A	 	 	 	9,244,987	 	
Long-term debt, including current maturities	 	$	1,705,634	 	 	$	3,194,340	 	 	$	6,857,055	 	 	$	7,782,648	 	 	 	N/A	 	 	$	4,129,011	 	

N/A — Not Applicable.

     The following table provides the detail of our revenues from majority-owned operations:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Reorganized	
 	 	Predecessor Company

	 	NRG

	
 	 	Year Ended December 31,	 	January 1 -	 	December 6 -	

	 	December 5,	 	December 31,	
 	 	1999

	 	2000

	 	2001

	 	2002

	 	2003

	 	2003

	
 	 	 	 	 	 	 	 	 	 	(In thousands)	 	 	 	 	 	 	 	 	
Energy and energy related	 	$	3,292	 	 	$	1,091,115	 	 	$	1,376,044	 	 	$	1,183,514	 	 	$	992,626	 	 	$	78,018	 	
Capacity	 	 	4,288	 	 	 	405,697	 	 	 	490,315	 	 	 	553,321	 	 	 	565,965	 	 	 	39,955	 	
Alternative energy	 	 	83,343	 	 	 	92,671	 	 	 	161,845	 	 	 	97,712	 	 	 	115,911	 	 	 	12,064	 	
O&M Fees	 	 	9,502	 	 	 	10,073	 	 	 	15,789	 	 	 	14,413	 	 	 	12,942	 	 	 	1,135	 	
Other	 	 	318,463	 	 	 	65,701	 	 	 	41,604	 	 	 	89,589	 	 	 	111,170	 	 	 	7,335	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total revenues from majority- owned operations	 	$	418,888	 	 	$	1,665,257	 	 	$	2,085,597	 	 	$	1,938,549	 	 	$	1,798,614	 	 	$	138,507	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
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     Energy and energy related revenue consists of revenues received upon the physical delivery of electrical energy to a third party at both spot (merchant sales) and contracted rates. In addition, we also generate revenues from the sale of ancillary services and by entering into certain financial transactions. Ancillary revenues are derived from the sale of energy related products associated with the generation of electrical energy such as spinning reserves, reactive power and other similar products. Revenues derived from financial transactions are generally received upon the settlement of transactions relating to the sale of energy or fuel which do not require the physical delivery of the underlying commodity.

     Capacity revenue consists of revenues received from a third party at either spot (merchant sales) or negotiated contract rates for making installed generation capacity available upon demand in order to satisfy system integrity and reliability requirements. In addition, capacity revenues includes revenues received under tolling arrangements which entitle third parties to dispatch our facilities and assume title to the electrical generation produced from that facility.

     Alternative energy revenue consists of revenues received from the sale of steam, hot and chilled water generally produced at a central district energy plant and sold to commercial, governmental and residential buildings for space heating, domestic hot water heating and air conditioning. Alternative energy revenue includes the sale of high-pressure steam produced and delivered to industrial customers that is used as part of an industrial process. In addition, alternative revenue includes revenues received from the processing of municipal solid waste into refuse derived fuel that is sold to a third party to be used as fuel in the generation of electricity.

     O&M fees consist of revenues received from providing certain unconsolidated affiliates with management and operational services generally under long-term operating agreements.

     Other revenues consist of miscellaneous other revenues derived from the sale of natural gas, recovery of incurred costs under reliability agreements and revenues received under leasing arrangements.

Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations

Overview

     We are a wholesale power generation company, primarily engaged in the ownership and operation of power generation facilities and the sale of energy, capacity and related products in the United States and internationally. We have a diverse portfolio of electric generation facilities in terms of geography, fuel type and dispatch levels, which help us, mitigate risk. We intend to maximize operating income through the efficient procurement and management of fuel supplies and maintenance services, and the sale of energy, capacity and ancillary services into attractive spot, intermediate and long-term markets.

     Our focus will continue to be on the operating performance of our entire portfolio and, in particular, on developing the assets in our core regions into integrated businesses well-suited to serving the requirements of the load-serving entities in our core markets. Power sales, fuel procurement and risk management will remain a key strategic element of these regional businesses contributing to our overall objective to optimize the operating income generated by all of our facilities within an appropriate risk and liquidity profile. Our business will involve the reinvestment of capital in our existing assets for reasons of life extension, repowering, expansion, environmental remediation, operating efficiency, greater fuel optionality or for alternative use, among other reasons. Our business also may involve select acquisitions intended to complement and enhance the commercial performance of the asset portfolios in our core regions.

     Industry Trends. In this “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” we discuss our historical results of operations and expected financial condition. During 2002 and 2003, the following factors, among others, have negatively affected our results of operations:
•	 	weak markets for electric energy, capacity and ancillary services;	 	
 	
•	 	a narrowing of the “spark spread” (the difference between power prices and fuel costs) in most regions of the United States in which we operate power generation facilities offset by our coal-fired assets, which gain a competitive advantage when gas prices rise;	 	 	

•	 	mild weather during peak seasons in regions where we have significant merchant capacity;	

•	 	reduced liquidity in the energy trading markets as a result of fewer participants trading lower volumes;	
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•	 	the imposition of price caps and other market mitigation in markets where we have significant merchant capacity;	

•	 	regulatory and market frameworks in certain regions where we operate that prevent us from charging prices that will enable us to recover our operating costs and to earn acceptable returns on capital; however, we benefited from the FERC acceptance of certain RMR agreements subject to refund;	

•	 	the obligation through 2003 to perform under certain long-term contracts that are not profitable;	

•	 	physical, regulatory and market constraints on transmission facilities in certain regions that limit or prevent us from selling power generated by certain of our facilities;	

•	 	limited access to capital due to our financial condition since July 2002 and the resulting contraction of our ability to conduct business in the merchant energy markets; and	

•	 	changes and turnover in senior and middle management since June 2002 in connection with our restructuring.	
     We expect that these generally weak market conditions will continue for the foreseeable future in some markets. Historically, we have believed that, as supply surpluses begin to tighten and as market rules and regulatory conditions stabilize, prices will improve for energy, capacity and ancillary services. This view is consistent with our belief that in the long run market prices will support an adequate rate of return on the construction of new power generation assets needed to meet increasing demand. This view is currently being challenged in certain markets as regulatory actions and market rules unfold that limit the ability of merchant power companies to earn favorable returns on existing and new investments. To the extent unfavorable regulatory and market conditions exist in the long term; we could have significant impairments of our property, plant and equipment, which, in turn, could have a material adverse effect on our results of operations. Further, this could lead to us closing certain of our facilities resulting in additional economic losses and liabilities.

     Asset Sales. As part of our strategy, we plan to continue the selective divestment of certain assets. Since July 2002, we have sold or made arrangements to sell a number of assets and equity investments. In addition, we are currently marketing our interest in certain other non-strategic assets.

     Discontinued Operations. We have classified certain business operations, and gains/losses recognized on sale, as discontinued operations for projects that were sold or have met the required criteria for such classification pending final disposition. Accounting regulations require that continuing operations are reported separately in the income statement from discontinued operations, and that any gain or loss on the disposition of any such business be reported along with the operating results of such business. Assets classified as “discontinued operations” on our balance sheet as of December 31, 2003 include McClain, Penobscot Energy Recovery Company (PERC), Compania Boliviana De Energia Electrica S.A. Bolivian Power Company Limited, or “Cobee”, LSP Energy and Hsin Yu projects. For the periods January 1, 2003 through December 5, 2003, discontinued results of operations include our McClain, PERC, Cobee, Killingholme, NEO Landfill Gas, Inc., or “NLGI”, three NEO Corporation projects (NEO Fort Smith LLC, NEO Woodville LLC, NEO Phoenix LLC), Timber Energy Resources, Inc., or “TERI”, Cahua, Energia Pacasmayo, LSP Energy and Hsin Yu projects. For the period December 6, 2003 through December 31, 2003, discontinued results of operations included McClain, PERC, Cobee, LSP Energy and Hsin Yu. All prior periods presented have been restated accordingly.

The following table summarizes our discontinued operations for all periods presented in our consolidated financial statements:

Discontinued Operations
 	 	 	 	 	
 	 	Initial	 	 	
 	 	Discontinued Operations	 	Disposal	
Projects

	 	Treatment

	 	Date

	
Bulo Bulo	 	Second Quarter 2002	 	Fourth Quarter 2002	
Crockett Cogeneration Project	 	Third Quarter 2002	 	Fourth Quarter 2002	
Csepel and Entrade	 	Third Quarter 2002	 	Fourth Quarter 2002	
Killingholme	 	Fourth Quarter 2002	 	First Quarter 2003	
NLGI	 	Second Quarter 2003	 	Second Quarter 2003	
NEO Corp. projects	 	Fourth Quarter 2003	 	Fourth Quarter 2003	
TERI	 	Third Quarter 2003	 	Third Quarter 2003	
Cahua and Pacasmayo	 	Fourth Quarter 2003	 	Fourth Quarter 2003	
McClain	 	Third Quarter 2003	 	Third Quarter 2004	
PERC	 	First Quarter 2004	 	Second Quarter 2004	
Cobee	 	First Quarter 2004	 	Second Quarter 2004	
LSP Energy	 	Second Quarter 2004	 	Third Quarter 2004	
Hsin Yu	 	Second Quarter 2004	 	Second Quarter 2004	

     New Management. On October 21, 2003, we announced the appointment of David Crane as our President and Chief Executive Officer, effective December 1, 2003. Before joining us, Mr. Crane served as the Chief Executive Officer of London-based International Power PLC and has over 12 years of energy industry experience. On March 11, 2004 we announced the appointment of Robert Flexon as Executive Vice President and Chief Financial Officer, effective March 29, 2004. Before joining us Mr. Flexon served as Vice President, Work Processes, Corporate Resources and Development at Hercules, Inc. In addition, we have filled several other senior and middle management positions over the last 12 months. Our board of directors currently is comprised of Mr. Crane and ten independent individuals, three of whom have been designated by MatlinPatterson, a significant holder of NRG common stock.

     Independent Registered Public Accounting Firm; Audit Committee. On May 3, 2004, we announced that we had initiated a search for a new independent auditor because PricewaterhouseCoopers LLP, our previous auditor, informed us that they would not be standing for re-election as our independent auditor for the year ended December 31, 2004. For each of the two fiscal years ended December 31, 2002 and 2003 and for the period from January 1, 2004 through April 27, 2004, there had been no disagreements with

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PricewaterhouseCoopers on any matters of accounting principles or practices, financial statement disclosure or auditing scope or procedure.

     On May 25, 2004, we announced that the audit committee of our board of directors had engaged KPMG LLP to serve as our independent auditor, effective immediately. On August 4, 2004, our stockholders ratified the appointment of KPMG LLP as our independent registered public accounting firm at our 2004 annual meeting of stockholders. KPMG’s engagement with us commenced with its review of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2004.

     Our new board of directors appointed an audit committee consisting entirely of independent directors in January 2004. Pursuant to its charter, the committee appoints, retains, oversees, evaluates, compensates and terminates on its sole authority our independent auditors and approves all audit engagements, including the scope, fees, and terms of each engagement. The audit committee’s oversight process is intended to ensure that we will continue to have high-quality, cost efficient independent auditing services.

Results of Operations

     Due to the adoption of Fresh Start as of December 5, 2003, Reorganized NRG’s balance sheet, statement of operations and statement of cash flows have not been prepared on a consistent basis with, and are therefore generally not comparable to those of the Predecessor Company prior to the application of Fresh Start. In accordance with SOP 90-7, Reorganized NRG’s balance sheet, statement of operations and statement of cash flows have been presented separately from those of the Predecessor Company.

     Reorganized NRG’s revenues from majority-owned operations, operating costs and expenses and general, administrative and development expenses, were not significantly affected by the adoption of Fresh Start. Therefore, the Predecessor Company’s 2003 amounts have been combined with Reorganized NRG’s 2003 amounts for comparison and analysis purposes herein.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor Company

	 	Reorganized NRG

	
 	 	 	 	 	 	 	 	 	 	For the Period	 	For the Period	 	 	
 	 	Year Ended December 31,	 	January 1 -	 	December 6 -	 	 	

	 	December 5,	 	December 31,	 	 	
 	 	2001

	 	2002

	 	2003

	 	2003

	 	Total 2003

	
 	 	 	 	 	 	(In thousands)	 	 	 	 	 	 	 	 	
Revenues from majority- owned operations	 	$	2,085,597	 	 	$	1,938,549	 	 	$	1,798,614	 	 	$	138,507	 	 	$	1,937,121	 	
Cost of majority-owned operations	 	 	1,377,093	 	 	 	1,334,263	 	 	 	1,357,531	 	 	 	95,602	 	 	 	1,453,133	 	
General, administrative and development	 	 	187,302	 	 	 	218,914	 	 	 	170,392	 	 	 	12,541	 	 	 	182,933	 	
     Reorganized NRG’s net loss, equity in earnings of unconsolidated affiliates, depreciation and amortization, other income (expense), other charges, income taxes and discontinued operations were affected by the adoption of Fresh Start. Therefore, the Predecessor Company’s 2003 and the Reorganized NRG’s 2003 amounts are discussed separately for comparison and analysis purposes herein.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	Reorganized	
 	 	Predecessor Company

	 	NRG

	
 	 	 	 	 	 	 	 	 	 	For the Period	 	For the Period	
 	 	Year Ended December 31	 	January 1 -	 	December 6 -	

	 	December 5,	 	December 31,	
 	 	2001

	 	2002

	 	2003

	 	2003

	
 	 	 	 	 	 	(In thousands)	 	 	 	 	
Net income/(loss)	 	$	265,204	 	 	$	(3,464,282	)	 	$	2,766,445	 	 	$	11,025	 	
Depreciation and amortization	 	 	142,083	 	 	 	208,149	 	 	 	219,201	 	 	 	11,808	 	
Other income/(expense)	 	 	(131,096	)	 	 	(572,230	)	 	 	(286,904	)	 	 	(5,419	)	
Other charges/(credits)	 	 	—	 	 	 	2,563,060	 	 	 	(3,220,605	)	 	 	2,461	 	
Income tax expense/(benefit)	 	 	37,974	 	 	 	(166,867	)	 	 	37,929	 	 	 	(661	)	
Income/(loss) from discontinued operations	 	 	55,155	 	 	 	(673,082	)	 	 	(180,817	)	 	 	(312	)	
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For the Year Ended December 31, 2003 Compared to the Year Ended December 31, 2002

     Net Income

     Predecessor Company

     During the period January 1, 2003 through December 5, 2003, we recorded net income of $2.8 billion. Net income for the period is directly attributable to our emerging from bankruptcy and adopting the Fresh Start provisions of SOP 90-7. Upon the confirmation of our Plan of Reorganization and our emergence from bankruptcy we were able to remove significant amounts of long-term debt and other prepetition obligations from our balance sheet. Accordingly, as part of net income from continuing operations, we recorded a net gain of $4.1 billion as the impact of our adopting Fresh Start in our statement of operations, $6.0 billion of this amount is directly related to the forgiveness of debt and settlement of substantial amounts of our pre-petition obligations upon our emergence from bankruptcy. In addition to the removal of substantial amounts of pre-petition debt and other obligations from our balance sheet, we have also revalued our assets and liabilities to fair value, accordingly we have substantially written down the value of our fixed assets. We have recorded a net $1.7 billion charge related to the revaluation of our assets and liabilities within the Fresh Start Reporting adjustment line of our consolidated statement of operations. In addition to our recording adjustments related to our emergence from bankruptcy, we also recorded substantial charges related to other items such as the settlement of certain outstanding litigation in the amount of $462.6 million, write downs and losses on the sale of equity investments of $147.1 million, advisor cost and legal fees directly attributable to our being in bankruptcy of $197.8 million and $237.6 million of other asset impairment and restructuring costs incurred prior to our filing for bankruptcy. Net income for the period January 1, 2003 through December 5, 2003 was also favorably impacted by our not recording interest expense on substantial amounts of corporate level debt while we were in bankruptcy and by the continued favorable results experienced by our equity investments.

     During the year ended December 31, 2002, we recognized a net loss of $3.5 billion. The loss from continuing operations incurred during 2002 primarily consisted of $2.6 billion of other charges consisting primarily of asset impairments.

     Reorganized NRG

     During the period December 6, 2003 through December 31, 2003, we recognized net income of $11.0 million or $0.11 per share of common stock. Net income was directly attributable to a number of factors some of which are discussed below. From an overall operational perspective our facilities were profitable during this period. Our results were adversely impacted by our having to continue to satisfy the standard offer service contract that we entered into with Connecticut Light & Power, or “CL&P” in 2000. As a result of our inability to terminate this contract during our bankruptcy proceeding we continued to be exposed to losses under this contract. These losses were incurred, as we were unable to satisfy the requirements of this contract at a price/cost below the contracted sales price. Upon our adoption of Fresh Start, we recorded at fair value, all assets and liabilities on our opening balance sheet and accordingly we recorded as an obligation the fair value of the CL&P contract. During the period December 6, 2003 through December 31, 2003, we recognized as revenues, the entire fair value of this contract effectively offsetting the actual losses incurred under this contract. The CL&P contract terminated on December 31, 2003.

     Revenues from Majority Owned Operations

     Our operating revenues from majority owned operations were $1.9 billion in 2003, compared to $1.9 billion in the prior year, a decrease of $1.4 million or less than 1%.

     Revenues from majority owned operations of $1.9 billion for the year 2003, includes $1.1 billion of energy revenues, $605.9 million of capacity revenues, $128.0 million of alternative energy, $14.1 million of O&M fees and $118.5 million of other revenues which include financial and physical gas sales, sales from our Schkopau facility and NEPOOL expense reimbursements. The decrease of $1.4 million is due to increased capacity revenues resulting from additional projects becoming operational in the later part of 2002, higher sales in New York, and by our recognizing, as additional revenues, the fair value of the out-of-market CL&P contract upon our emergence from bankruptcy. Offsetting these increases, we continued to recognize losses on the CL&P contract throughout 2003 resulting from higher market prices and lower generation.

     Cost of Majority-Owned Operations

     Our cost of majority owned operations related to continuing operations was $1.5 billion in 2003, compared to $1.3 billion for 2002, an increase of $118.9 million or 8.9%. For 2003 and 2002, cost of majority owned operations represented 75.0% and 68.8% of revenues from majority owned operations, respectively. Cost of majority owned operations, consists primarily of cost of energy (primarily fuel costs), labor, operating and maintenance costs and non income based taxes related to our majority owned operations.

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     For the year 2003, cost of energy was $902.4 million compared to $900.9 million for 2002, representing an increase of $1.5 million. As a percent of revenue from majority owned operations, cost of energy was 46.6% and 46.5%, for 2003 and 2002, respectively. Cost of energy was directly affected by an overall decrease in the cost of fuel during 2003 and a favorable change in the fair value of our energy related derivatives resulting from contract terminations. Offsetting this decrease are liquidated damages of $72.9 million triggered from our financial condition.

     Depreciation and Amortization

     Predecessor Company

     Our depreciation and amortization expense related to continuing operations was $219.2 million for the period January 1, 2003 through December 5, 2003 and $208.1 million for the year ended December 31, 2002. Depreciation and amortization consists of the allocation of our historical depreciable fixed asset costs over the remaining lives of such property as well as the amortization of certain contract based intangible assets.

     Reorganized NRG

     Our depreciation and amortization expense related to continuing operations was $11.8 million for the period December 6, 2003 through December 31, 2003. Depreciation and amortization consists of the allocation of our newly valued basis in our fixed assets over newly determined remaining fixed asset lives. As part of adopting the Fresh Start concepts of SOP 90-7 our tangible fixed assets were recorded at fair value as determined by a third party valuation expert who we also consulted with in determining the appropriate remaining lives for our tangible depreciable property. Depreciation expense for this period was based on preliminary depreciable lives and asset balances.

     General, Administrative and Development

     Our general, administrative and development costs for 2003 were $182.9 million compared to $218.9 million for 2002, a decrease of $36.0 million or 16.4%. For 2003 and 2002, general, administrative and development costs represent 9.4% and 11.3% of revenues from majority owned operations, respectively. This decrease is due to decreased costs related to work force reduction efforts, cost reductions due to the closure of certain international offices and reduced legal costs. Outside services also decreased, due to less non-restructuring legal activities.

     Other Charges (Credits)

     During the period January 1, 2003 to December 5, 2003, we recorded other credits of $3.2 billion, which consisted primarily of $228.9 million related to asset impairments, $462.6 million related to legal settlements and $197.8 million related to reorganization charges and $8.7 million related to restructuring charges. We also incurred a $4.1 billion credit related to Fresh Start adjustments. During 2002, we recorded other charges of $2.6 billion, which consisted primarily of $2.5 billion related to asset impairments and $111.3 million related to restructuring charges.

     We review the recoverability of our long-lived assets on a periodic basis and if we determined that an asset was impaired, we compared asset-carrying values to total future estimated undiscounted cash flows. Separate analyses are completed for assets or groups of assets at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The estimates of future cash flows included only future cash flows, net of associated cash outflows, directly associated with and expected to arise as a result of our assumed use and eventual disposition of the asset. Cash flow estimates associated with assets in service are based on the asset’s existing service potential. The cash flow estimates may include probability weightings to consider possible alternative courses of action and outcomes, given the uncertainty of available information and prospective market conditions.

     If an asset was determined to be impaired based on the cash flow testing performed, an impairment loss was recorded to write down the asset to its fair value. Estimates of fair value were based on prices for similar assets and present value techniques. Fair values determined by similar asset prices reflect our current estimate of recoverability from expected marketing of project assets. For fair values determined by projected cash flows, the fair value represents a discounted cash flow amount over the remaining life of each project that reflects project-specific assumptions for long-term power pool prices, escalated future project operating costs, and expected plant operation given assumed market conditions.

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     Impairment charges (credits) included the following for the year ended December 31, 2002 and for the period January 1, 2003 to December 5, 2003 and the period December 6, 2003 through December 31, 2003.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	Reorganized	 	 	
 	 	 	 	Predecessor Company

	 	NRG

	 	 	
 	 	 	 	 	 	 	 	For the Period	 	For the Period	 	 	
 	 	 	 	Year Ended	 	January 1 -	 	December 6 -	 	 	
 	 	 	 	December 31,	 	December 5,	 	December 31,	 	 	
Project Name

	 	Project Status

	 	2002

	 	2003

	 	2003

	 	Fair Value Basis

	
Devon Power LLC	 	Operating at a loss	 	$	—	 	 	$	64,198	 	 	$	—	 	 	Projected cash flows	
Middletown Power LLC	 	Operating at a loss	 	 	—	 	 	 	157,323	 	 	 	—	 	 	Projected cash flows	
Arthur Kill Power, LLC	 	Terminated construction	 	 	—	 	 	 	9,049	 	 	 	—	 	 	Projected cash flows	
 	 	project	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Langage (UK)	 	Terminated	 	 	42,333	 	 	 	(3,091	)	 	 	—	 	 	Estimated market	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	price/Realized gain	
Turbine	 	Sold	 	 	—	 	 	 	(21,910	)	 	 	—	 	 	Realized gain	
Berrians Project	 	Terminated	 	 	—	 	 	 	14,310	 	 	 	—	 	 	Realized loss	
Termo Rio	 	Terminated	 	 	—	 	 	 	6,400	 	 	 	—	 	 	Realized loss	
Nelson	 	Terminated	 	 	467,523	 	 	 	—	 	 	 	—	 	 	Similar asset prices	
Pike	 	Terminated	 	 	402,355	 	 	 	—	 	 	 	—	 	 	Similar asset prices	
Bourbonnais	 	Terminated	 	 	264,640	 	 	 	—	 	 	 	—	 	 	Similar asset prices	
Meriden	 	Terminated	 	 	144,431	 	 	 	—	 	 	 	—	 	 	Similar asset prices	
Brazos Valley	 	Foreclosure completed	 	 	102,900	 	 	 	—	 	 	 	—	 	 	Projected cash flows	
 	 	in January 2003	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Kendall and other expansion Projects	 	Terminated	 	 	55,300	 	 	 	—	 	 	 	—	 	 	Projected cash flows	
Turbines & other costs	 	Equipment being	 	 	701,573	 	 	 	—	 	 	 	—	 	 	Similar asset prices	
 	 	marketed	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Audrain	 	Operating at a loss	 	 	66,022	 	 	 	—	 	 	 	—	 	 	Projected cash flows	
Somerset	 	Operating at a loss	 	 	49,289	 	 	 	—	 	 	 	—	 	 	Projected cash flows	
Bayou Cove	 	Operating at a loss	 	 	126,528	 	 	 	—	 	 	 	—	 	 	Projected cash flows	
Other	 	 	 	 	28,851	 	 	 	2,617	 	 	 	—	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	
Total impairment charges (credits)	 	 	 	$	2,451,745	 	 	$	228,896	 	 	$	—	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	
     Reorganization Items

     For the period from January 1, 2003 to December 5, 2003, we incurred $197.8 million in reorganization costs and for the period from December 6, 2003 to December 31, 2003 we incurred $2.5 million in reorganization costs. All reorganization costs have been incurred since we filed for bankruptcy in May 2003. The following table provides the detail of the types of costs incurred (in thousands):
 	 	 	 	 	 	 	 	 	
 	 	Predecessor	 	Reorganized	
 	 	Company

	 	NRG

	
 	 	For the Period	 	For the Period	
 	 	January 1 -	 	December 6 -	
 	 	December 5,	 	December 31,	
 	 	2003

	 	2003

	
Reorganization items	 	 	 	 	 	 	 	 	
Professional fees	 	$	82,186	 	 	$	2,461	 	
Deferred financing costs	 	 	55,374	 	 	 	—	 	
Pre-payment settlement	 	 	19,609	 	 	 	—	 	
Interest earned on accumulated cash	 	 	(1,059	)	 	 	—	 	
Contingent equity obligation	 	 	41,715	 	 	 	—	 	

 	 	 	 	

 	 	
Total reorganization items	 	$	197,825	 	 	$	2,461	 	

 	 	 	 	

 	 	
     Restructuring Charges

     We incurred total restructuring charges of approximately $111.3 million for the year ended December 31, 2002. These costs consisted of employee separation costs and advisor fees. We incurred an additional $8.7 million of employee separation costs and advisor fees during 2003 until we filed for bankruptcy in May 2003. Subsequent to that date we recorded all advisor fees as reorganization costs.

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     Legal Settlement Costs

     During 2003, we recorded $396.0 million in connection with the resolution of the FirstEnergy Arbitration Claim. As a result of this resolution, FirstEnergy retained ownership of the Lake Plant Assets and received an allowed general unsecured claim of $396.0 million under the NRG plan of reorganization submitted to the bankruptcy court.

     In November 2003, we settled various litigation with Fortistar Capital in which Fortistar Capital released us from all litigation claims in exchange for a $60.0 million pre-petition claim and an $8.0 million post-petition claim. We had previously recorded $10.8 million in connection with various legal disputes with Fortistar Capital; accordingly, we recorded an additional $57.2 million during November 2003.

     In August of 1995, we entered into a Marketing, Development and Joint Proposing Agreement or “the Marketing Agreement”, with Cambrian Energy Development LLC, or “Cambrian.” Various claims had arisen in connection with this Marketing Agreement. In November 2003, we entered into a Settlement Agreement with Cambrian where we agreed to transfer our 100% interest in three gasco projects (NEO Ft. Smith, NEO Phoenix and NEO Woodville) and our 50% interest in two genco projects (MM Phoenix and MM Woodville) to Cambrian. In addition, we agreed to pay approximately $1.8 million in settlement of royalties incurred in connection with the Marketing Agreement. We had previously recorded a liability for royalties owed to Cambrian; therefore, we recorded an additional $1.4 million during November 2003.

     In November 2003, we settled our dispute with Dick Corporation in connection with Meriden Gas Turbines, which resulted in our recording an additional liability of $8.0 million in November 2003.

     Fresh Start Adjustments

     During the fourth quarter of 2003, we recorded a credit of $4.1 billion in connection with fresh start adjustments as discussed in Item 15 — Note 3. Following is a summary of the significant effects of the reorganization and Fresh Start:
 	 	 	 	 	
 	 	(In millions)	
Discharge of corporate level debt	 	$	5,162	 	
Discharge of other liabilities	 	 	811	 	
Establishment of creditor pool	 	 	(1,040	)	
Receivable from Xcel	 	 	640	 	
Revaluation of fixed assets	 	 	(1,392	)	
Revaluation of equity investments	 	 	(207	)	
Valuation of SO(2) emission credits	 	 	374	 	
Valuation of out of market contracts, net	 	 	(400	)	
Fair market valuation of debt	 	 	108	 	
Valuation of pension liabilities	 	 	(61	)	
Other valuation adjustments	 	 	(100	)	

 	 	
Total Fresh Start adjustments	 	 	3,895	 	
Less discontinued operations	 	 	224	 	

 	 	
Total Fresh Start adjustments – continuing operations	 	$	4,119	 	

 	 	
     Other Income (Expense)

     Predecessor Company

     During the period January 1, 2003 through December 5, 2003, we recorded other expense of $286.9 million. Other expense consisted primarily of $329.9 million of interest expense and $147.1 million of write downs and losses on sales of equity method investments, partially offset by equity in earnings of unconsolidated affiliates of $170.9 million and $19.2 million of other income.

     For the year ended December 31, 2002, other expenses was $572.2 million, which consisted primarily of $452.2 million of interest expense and $200.5 million of write downs and losses on sales of equity method investments.

     Interest expense for the period January 1, 2003 through December 5, 2003 of $329.9 million consisted of interest expense on both our project and corporate level interest bearing debt. In addition, interest expense includes the amortization of debt issuance costs and

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any interest rate swap termination costs. Subsequent to our entering into bankruptcy we ceased the recording of interest expense on our corporate level debt as these prepetition claims were deemed to be impaired and subject to compromise. We did not however cease to record interest expense on the project level debt outstanding at our Northeast Generating and South Central Generating facilities even though these entities were also in bankruptcy as these claims were deemed to be most likely not impaired and not subject to compromise. We also recorded substantial amounts of fees and costs related to our acquiring a debtor in possession financing arrangement while we were in bankruptcy. In addition, upon our emergence from bankruptcy we wrote off any remaining deferred finance costs related to our corporate and project level debt including our Northeast and South Central project level debt as it was probable that they would be refinanced upon our emergence from bankruptcy.

     Reorganized NRG

     Other income (expense) for the period December 6, 2003 through December 31, 2003, was an expense of $5.4 million and consisted primarily of $18.9 million of interest expense, partially offset by $13.5 million of equity earnings from unconsolidated subsidiaries.

     Interest expense for the period December 6, 2003 through December 31, 2003 of $18.9 million consists primarily of interest expense at the corporate level, primarily related to the newly issued high yield notes, term loan facility and revolving line of credit used to refinance certain project level financings. In addition, interest expense includes the amortization of deferred financing costs incurred as a result of our refinancing efforts and the amortization of discounts and premiums recorded upon the marking of our debt to fair value upon our adoption of the Fresh Start provision of SOP 90-7.

     Minority Interest in Earnings of Consolidated Subsidiaries

     For the period December 6, 2003 through December 31, 2003, minority interest in earnings of consolidated subsidiaries was $134,000 and relates primarily to Northbrook New York and Northbrook Energy.

     Write-Downs and Losses on Sales of Equity Method Investments

     As we periodically review our equity method investments for impairments we have taken substantial write-downs and losses on sales of equity method investments during the period January 1, 2003 through December 5, 2003 and for the year 2002. In 2003 we recorded impairments and losses on the sales of investments of $147.1 million compared to $200.5 million in 2002. The $147.1 million recorded in 2003 consists of the write down of our investment in the Loy Yang project of $146.4 million and our investment in the NEO Corporation — Minnesota Methane project of $12.3 million during 2003. These losses were partially offset by gains on the sale of our investment in the ECKG and Mustang projects. During 2002 we recorded write-downs and losses on sales of equity method investments of $200.5 million. The $200.5 million recorded in 2002 consists of a write down of our investment in the Loy Yang project of $111.4 million, a loss of $48.4 million on the transfer of our interest in the Sabine River Works project to our partner, a $14.2 million write down related to our investment in our EDL project, a write down of our investment in our Kondapalli project of $12.7 million and a write down of our investment in NEO Corporation — Minnesota Methane and MM Biogas of $12.3 million and $3.3 million, respectively among others. See Item 15 — Note 7 to the Consolidated Financial Statements for additional information.

     Equity Earnings from Unconsolidated Affiliates

     Predecessor Company

     During the period January 1, 2003 through December 5, 2003, we recorded $170.9 million of equity earnings from investments in unconsolidated affiliates. Our 50% investment in West Coast Power comprised $98.7 million of this amount with our investments in the Mibrag, Loy Yang, Gladstone and Rocky Road projects comprising $21.8 million, $17.9 million, $12.4 million and $6.9 million, respectively, with the remaining amounts attributable to various domestic and international equity investments. Our investment in West Coast Power continues to generate favorable earnings as well as our investments in Mibrag, Loy Yang, Gladstone and Rocky Road. For the year ended December 31, 2002, equity earnings from investments in unconsolidated affiliates was $69.0 million.

     Reorganized NRG

     Equity in earnings of unconsolidated affiliates of $13.5 million consists primarily of equity earnings from our 50% ownership in West Coast Power of $9.3 million.

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     Discontinued Operations

      During the first quarter of 2004, we determined that two additional projects had met the necessary criteria for discontinued operations treatment, Penobscot Energy Recovery Company , or “PERC ” and Compania Boliviana De Energia Electrica S.A. Bolivian Power Company Limited, or “Cobee” accordingly, all periods presented have been restated to reflect the addition of these projects as discontinued operations.

      During the second quarter of 2004, we determined that two more projects had met the necessary criteria for discontinued operations treatment, LSP Energy and Hsin Yu. Accordingly, all periods presented have been restated to reflect the addition of these projects as discontinued operations.

     Predecessor Company

     As of December 5, 2003, we classified as discontinued operations the operations and gains/losses recognized on the sales of projects that were sold or were deemed to have met the required criteria for such classification pending final disposition. For the period January 1, 2003 through December 5, 2003, discontinued operations consist of the historical operations and net gains/losses related to our Killingholme, McClain, PERC, Cobee, NLGI, NEO Corporation projects, TERI, Cahua, Energia Pacasmayo, LSP Energy and Hsin Yu projects. Discontinued operations for the year ended December 31, 2002 consisted of our Crockett Cogeneration, Entrade, Killingholme, Csepel, Bulo Bulo, McClain, PERC, Cobee, NLGI, TERI, Cahua, Energia Pacasmayo, LSP Energy and Hsin Yu projects.

     For the period January 1, 2003 through December 5, 2003, the results of operations related to such discontinued operations was a net loss of $180.8 million due to a loss on the sale of our Peru projects, impairment charges recorded at McClain and NLGI and fresh start adjustment at LSP Energy.

     During 2002 we recognized a loss on discontinued operations of $673.1 million due to asset impairments recorded at Killingholme, NLGI, TERI, LSP Energy and Hsin Yu projects.

     Reorganized NRG

     Discontinued operations for the period December 6, 2003 through December 31, 2003 is comprised of a loss of $0.3 million attributable to the on going operations of our McClain, PERC, Cobee, LSP Energy and Hsin Yu projects.

     Income Tax

     Predecessor Company

     Income tax benefit/expense for the period January 1, 2003 through December 5, 2003 was a tax expense of $37.9 million as compared to a tax benefit of $166.9 million for the year ended December 31, 2002. The income tax expense for the period ended December 5, 2003 was primarily due to separate company income tax liabilities and an increase in the valuation allowance against deferred tax assets. An additional valuation allowance of $33 million was recorded against deferred tax assets of NRG West Coast as a result of its conversion from a corporation to a single member limited liability company (a disregarded entity for federal income tax purposes).

     The effective income tax rate for the period January 1, 2003 through December 5, 2003 is relatively low since the U.S. net operating loss carryforwards are offset by the cancellation of debt income resulting from the Bankruptcy. The income tax benefit for the year ended December 31, 2002 was primarily due to the increase in deferred tax assets relating to impairments recognized for financial reporting purposes. A valuation allowance was increased limiting the recognition of deferred tax assets to the extent of previously recorded deferred tax liabilities.

     Income taxes have been recorded on the basis that our U.S. subsidiaries and we will file separate federal income tax returns for the period January 1, 2003 through December 5, 2003. Since our U.S. subsidiaries and we will not be included in the Xcel Energy consolidated tax group, each of our U.S. subsidiaries that is classified, as a corporation for U.S. income tax purposes must file a separate federal income tax return. It is uncertain if, on a stand-alone basis, we would be able to fully realize deferred tax assets related to net operating losses and other temporary differences, therefore a full valuation allowance has been established.

     Reorganized NRG

     Income tax benefit/expense for the period December 6, 2003 through December 31, 2003 was a tax benefit of $0.7 million which consists of a U.S. tax benefit of $1.5 million and foreign tax expense of $0.8 million. The foreign tax expense for the period is due to earnings in the foreign jurisdictions.

     Our U.S. subsidiaries and we will file a consolidated federal income tax return for the period December 6, 2003 through December 31, 2003. With the exception of alternative minimum tax, or “AMT”, we anticipate that our cash tax rate for the next 5 years will be relatively low as we realize the cash tax benefits from using our net operating loss carryforwards. For AMT purposes, utilization of net operating losses is limited on an annual basis.

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     Due to the uncertainty of realization of deferred tax assets related to net operating losses and other temporary differences, the change in U.S. current and deferred income taxes has been fully offset by a change in the valuation allowance and our U.S. net deferred tax assets at December 31, 2003 were offset by a full valuation allowance in accordance with SFAS 109. Regarding the valuation allowance as of December 5, 2003, SOP 90-7 requires any future benefits from reducing the valuation allowance from preconfirmation net operating loss carryforwards be reported as a direct addition to paid-in-capital versus a benefit on our income statement. Consequently, our effective tax rate in post Bankruptcy emergence years will not benefit from utilization of our net operating loss carryforwards which were fully valued as of the date of our emergence from Bankruptcy.

     As of December 31, 2003, our management intends to indefinitely reinvest the earnings from our foreign operations. Accordingly, U.S. income taxes and foreign withholding taxes were not provided on the earnings of our foreign subsidiaries.

     For the Year Ended December 31, 2002 Compared to the Year Ended December 31, 2001

     Net Income/(Loss)

     During the year ended December 31, 2002, we recognized a net loss of $3.5 billion. This loss represented a decrease in earnings of $3.7 billion compared to net income of $265.2 million for the same period in 2001. Our loss from continuing operations was $2.8 billion for the year ended December 31, 2002 compared to net income of $210.0 million from continuing operations for the same period in 2001. The loss from continuing operations incurred during 2002 primarily consists of $2.6 billion of other charges consisting primarily of asset impairments.

     During 2002, our continuing operations experienced less favorable results than those experienced during the same period in 2001. Overall, our domestic power generation operations performed poorly compared to the same period in 2001. Our domestic operations experienced reductions in domestic energy and capacity sales and an overall decrease in power pool prices and related spark spreads (the monetary difference between the price of power and fuel cost). During the fourth quarter of 2002, an additional reserve for uncollectible receivables in California was established by West Coast Power, the California joint venture of which we own 50%, which reduced our equity in the earnings of that joint venture by approximately $58.5 million on a pre-tax basis. In addition, West Coast Power’s results were already less than those recorded in 2001 due to less favorable contracts and reductions in sales of energy and capacity. In addition, increased administrative costs, depreciation and interest expense from completed construction costs also contributed to the less than favorable results in 2002. Partially offsetting these earnings reductions was the recognition, in the fourth quarter of 2002, of approximately $51.0 million of additional revenues related to the contractual termination of a power purchase agreement with our Indian River project.

     During the third quarter of 2002, we experienced credit rating downgrades, defaults under certain credit agreements, increased collateral requirements and reduced liquidity. These events led to impairments of a number of our assets, resulting in pre-tax charges related to continuing operations of approximately $2.5 billion during 2002. In addition, approximately $200.5 million of net losses on sales and write-downs of equity method investments were recorded in 2002.

     Operating results of majority-owned projects that were sold or have met the criteria to be considered as held-for-sale have been classified as discontinued operations. The period ended December 31, 2002, consisted of the historical operations and net gains/losses related to our Crockett Cogeneration, Entrade, Killingholme, Csepel, Bulo Bulo, McClain, PERC, Cobee, NLGI, NEO Fort Smith LLC, NEO Woodville LLC, NEO Phoenix LLC, TERI, Cahua, Energia Pacasmayo, LSP Energy and Hsin Yu Projects.

     During 2002, we expensed approximately $111.3 million for costs related to our financial restructuring. These costs include expenses for financial and legal advisors, contract termination costs, employee separation and other restructuring activities.

     Revenues from Majority-Owned Operations

     Our operating revenues from majority-owned operations were $1.9 billion in 2002 compared to $2.1 billion in the prior year, a decrease of $147.0 million or approximately 7.1%. Revenues from majority-owned operations for the year ended December 31, 2002, consisted primarily of power generation revenues from domestic operations of approximately $1.5 billion in 2002 compared with $1.6 billion in 2001, a decrease of $158.1 million. This decrease in domestic generation revenue is due to reductions in energy and capacity sales and an overall decrease in power pool prices.

     The Northeast region experienced decreased revenues, as they were significantly affected by a combination of lower capacity revenues and a decline in megawatt hour generation compared with 2001. This decline in generation is attributable to an unseasonably

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warm winter and cooler spring and a slowing economy, which reduced demand for electricity, together with new regulation, which reduced price volatility, particularly in New York City.

     Our International revenues from majority-owned operations decreased by $6.9 million or 2.4% from 2001 to 2002. The Australia region reported a reduction in revenues of $42.5 million while increases were reported from the Other International region of $35.6 million. The reduction in Australia revenue is primarily due to a decline in energy prices and the loss of a significant contract at Flinders. The increase in Other International revenue is primarily due to a full year of operations for acquisitions made in 2001.

     Operating Costs and Expenses

     For the year ended December 31, 2002, cost of majority-owned operations related to continuing operations was $1.3 billion compared to $1.4 billion for 2001, a decrease of $42.8 million or approximately 3.1%. For the years ended December 31, 2002 and 2001, cost of majority-owned operations represented approximately 68.8% and 66.0% of revenues from majority-owned operations, respectively. Cost of majority-owned operations consists primarily of cost of energy (primarily fuel costs), labor, operating and maintenance costs and non-income based taxes related to our majority-owned operations.

     For the year ended December 31, 2002, cost of energy was $900.9 million compared to $971.4 million for the year ended December 31, 2001. This represents a decrease of $70.5 million or 7.3%. As a percent of revenue from majority-owned operations cost of energy was 46.5% and 46.6% for the years ended December 31, 2002 and 2001, respectively.

     For the year ended December 31, 2002, operating and maintenance costs were $361.4 million compared to $321.1 million for the year ended December 31, 2001. This represents an increase of $40.3 million or 12.6%. As a percent of revenue from majority-owned operations, operating and maintenance costs represented 18.6% and 15.4%, for the years ended December 31, 2002 and 2001, respectively. The increase in operating and maintenance expense is primarily due to a full year of expense in 2002 related to assets acquired during 2001.

     Depreciation and Amortization

     For the year ended December 31, 2002, depreciation and amortization related to continuing operations was $208.1 million, compared to $142.1 million for the year ended December 31, 2001, an increase of $66.0 million or approximately 46.5%. This increase is primarily due to the addition of property, plant and equipment related to our acquisitions of electric generating facilities completed during 2002.

     General, Administrative and Development

     For the year ended December 31, 2002, general, administrative and development costs were $218.9 million, compared to $187.3 million for the year ended December 31, 2001, an increase of $31.6 million or approximately 16.9%. For the year ended December 31, 2002 and 2001, general, administrative and development costs represent 11.3% and 9.0% of revenues from majority-owned operations, respectively. This increase is primarily due to an increase in bad debt expense. Additionally there was an increase in other general administrative expenses due to 2001 acquisitions and newly constructed facilities coming on line. These increases were partially offset by decreases in business development expenses and other reductions to costs previously incurred to support international and expanded operations.

     Other Charges

     During the third quarter of 2002, we experienced credit rating downgrades, defaults under certain credit agreements, increased collateral requirements and reduced liquidity. We applied the provisions of SFAS No. 144 to our construction and operational projects. We completed an analysis of the recoverability of the asset carrying values of our projects factoring in the probability of different courses of action available to us given our financial position and liquidity constraints. As a result, we determined during the third quarter that many of our construction projects and certain operational projects were impaired and should be written down to fair market value. To estimate fair value, our management considered discounted cash flow analyses, bids and offers related to those projects and prices of similar assets. During 2002, we recorded asset impairment and other special charges related to continuing operations of $2.6 billion. See Item 15 — Note 8 to the Consolidated Financial Statements for additional information.

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     Other Income (Expense)

     For the year ended December 31, 2002, total other expense was $572.2 million, compared to $131.1 million for the year ended December 31, 2001, an increase of $441.1 million or approximately 336.5%. The increase in total other expense from 2001 consisted primarily of an increase in interest expense and $200.5 million of write downs and losses on sales of equity method investments combined with lower equity earnings of unconsolidated affiliates.

     For the year ended December 31, 2002, we had equity in earnings of unconsolidated affiliates of $69.0 million, compared to $210.0 million for 2001, a decrease of $141.0 million or approximately 67.1%. The $141.0 million decrease in equity earnings from unconsolidated affiliates is due primarily to unfavorable results at West Coast Power in 2002 as compared to the same period in 2001. During 2002, West Coast Power had long-term contracts that were less favorable than those held in 2001. In addition during 2002, West Coast Power established reserves for certain receivables not considered recoverable from California PX. Our share of this reserve was approximately $58.5 million on a pre-tax basis.

     For the year ended December 31, 2002, interest expense (which includes both corporate and project level interest expense) was $452.2 million, compared to $364.1 million in 2001, an increase of $88.1 million or approximately 24.2%. This increase is due primarily to increased corporate and project level debt. We issued substantial amounts of long-term debt at both the corporate level (recourse debt) and project level (non-recourse debt) to either directly finance the acquisition of electric generating facilities or refinance short-term bridge loans incurred to finance such acquisitions.

     Other income was a gain of $11.4 million, as compared to $23.0 million for the year ended December 31, 2001, a decrease of $11.6 million, or approximately 50.3%. Other income consists primarily of interest income on cash balances and realized and unrealized foreign currency exchange gains and losses. Interest income was lower during 2002 due to lower interest from affiliates, primarily related to West Coast Power. In addition, there were significant foreign currency exchange losses during 2002.

     Write-Downs and Losses on Sales of Equity Method Investments

     For the year ended December 31, 2002, write-downs and losses on equity method investments were $200.5 million. The $200.5 million charge consists primarily of write-downs related to our investment in Loy Yang in the total amount of $111.4 million. In addition, we recorded a loss of $48.4 million upon the transfer of our investment in SRW Cogeneration and recorded write-downs of $14.2 million and $3.6 million of our investments in EDL and Collinsville, respectively.

     Income Tax

     Income tax benefit/expense for the year ended December 31, 2002 was a tax benefit of $166.9 million as compared to a tax expense of $38.0 million for the year ended December 31, 2001. The income tax benefit for the year ended December 31, 2002 was primarily due to the increase in deferred tax assets relating to impairments recognized for financial reporting purposes. A valuation allowance was increased limiting the recognition of deferred tax assets to the extent of previously recorded deferred tax liabilities. The income tax expense for the year ended December 31, 2001 was primarily due to U.S. and foreign operating earnings reduced by tax credits of $37.2 million.

     For 2002, income taxes were recorded on the basis that Xcel Energy would not include us in its consolidated federal income tax return following Xcel Energy’s acquisition of our public shares on June 3, 2002. Since Xcel Energy did not include us in its consolidated federal income tax return, we and each of our U.S. subsidiaries that is classified as a corporation for U.S. income tax purposes must file separate federal income tax returns. It is uncertain if, on a stand-alone basis, we will be able to fully realize deferred tax assets related to net operating losses and other temporary differences, consequently, a valuation allowance of $1.1 billion was recorded as of December 31, 2002.

     For 2001, our U.S. subsidiaries and we were included in the Xcel Energy consolidated federal income tax return through March 12, 2001, the date of our secondary public offering. For the remainder of the year, we filed a consolidated federal return with our U.S. subsidiaries. Income tax expense was recorded on current and deferred tax liabilities, partially offset by benefits from tax credits.

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     Discontinued Operations

     Subsequent to December 31, 2002, we determined that additional projects had met the necessary criteria for discontinued operations treatment, McClain, PERC, Cobee, NLGI, NEO Fort Smith LLC, NEO Woodville LLC, NEO Phoenix LLC, TERI, Cahua, Energia Pacasmayo, LSP Energy and Hsin Yu, accordingly, we have restated all periods presented to reflect the addition of these projects as discontinued operations.

     As of December 31, 2002, we classified the operations and gains/losses recognized on the sales of certain entities as discontinued operations. Discontinued operations consist of the historical operations and net gains/losses related to our Crockett Cogeneration, Entrade, Killingholme, Csepel, Bulo Bulo, McClain, PERC, Cobee, NLGI, NEO Fort Smith LLC, NEO Woodville LLC, NEO Phoenix LLC, TERI, Cahua, Energia Pacasmayo, LSP Energy and Hsin Yu that were sold in 2002 or were deemed to have met the required criteria for such classification pending final disposition. For 2002, the results of operations related to such discontinued operations was a net loss of $673.1 million as compared to a gain of $55.2 million for the same period in 2001. The primary reason for the loss recognized in 2002 is due to asset impairments recorded at Killingholme, TERI, NLGI, LSP Energy and Hsin Yu.

Reorganization and Emergence from Bankruptcy

     On May 14, 2003, we and 25 of our U.S. affiliates, filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code, “the Bankruptcy Code” in the United States Bankruptcy Court for the Southern District of New York, or the “bankruptcy court.”

     On May 15, 2003, NRG Energy, PMI, NRG Finance Company I LLC, NRGenerating Holdings (No. 23) B.V. and NRG Capital LLC, collectively “the Plan Debtors”, filed the NRG plan of reorganization and the related Disclosure Statement for Reorganizing Debtors’ Joint Plan of Reorganization Pursuant to Chapter 11 of the United States Bankruptcy Code, as subsequently amended, “the Disclosure Statement.” The Bankruptcy Court held a hearing on the Disclosure Statement on June 30, 2003, and instructed the Plan Debtors to include certain additional disclosures. The Plan Debtors amended the Disclosure Statement and obtained Bankruptcy Court approval for the Third Amended Disclosure Statement for Debtors’ Second Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the Bankruptcy Code.

     On November 24, 2003, the bankruptcy court issued an order confirming the NRG plan of reorganization, and the plan became effective on December 5, 2003. On September 17, 2003, the Northeast/South Central plan of reorganization was proposed after we secured the necessary financing commitments. On November 25, 2003, the bankruptcy court issued an order confirming the Northeast/South Central plan of reorganization and the plan became effective on December 23, 2003.

Financial Reporting by Entities in Reorganization under the Bankruptcy Code and Fresh Start

     Between May 14, 2003 and December 5, 2003, we operated as a debtor-in-possession under the supervision of the bankruptcy court. Our financial statements for reporting periods within that timeframe were prepared in accordance with the provisions of Statement of Position 90-7,  “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code” , or “SOP 90-7.”

     For financial reporting purposes, the close of business on December 5, 2003, represents the date of emergence from bankruptcy. As used herein, the following terms refer to the Company and its operations:
 	 	 	
“Predecessor Company”	 	The Company, pre-emergence from bankruptcy	
 	 	The Company’s operations, January 1, 2001 — December 5, 2003	
“Reorganized NRG”	 	The Company, post-emergence from bankruptcy
The Company’s operations, December 6, 2003 — December 31, 2003	
     The implementation of the NRG plan of reorganization resulted in, among other things, a new capital structure, the satisfaction or disposition of various types of claims against the Predecessor Company, the assumption or rejection of certain contracts, and the establishment of a new board of directors.

     In connection with the emergence from bankruptcy, we adopted Fresh Start in accordance with the requirements of SOP 90-7. The application of SOP 90-7 resulted in the creation of a new reporting entity. Under Fresh Start, the enterprise value of our company was allocated among our assets and liabilities on a basis substantially consistent with purchase accounting in accordance with SFAS No. 141  “Business Combinations” , or “SFAS No. 141.” Accordingly, we pushed down the effects of this allocation to all of our subsidiaries.

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     Under the requirements of Fresh Start, we have adjusted our assets and liabilities, other than deferred income taxes, to their estimated fair values as of December 5, 2003. As a result of marking our assets and liabilities to their estimated fair values, we determined that there was no excess reorganization value that was reallocated back to our tangible and intangible assets. Deferred taxes were determined in accordance with SFAS No. 109,  “Accounting for Income Taxes.”  The net effect of all Fresh Start adjustments resulted in a gain of $4.1 billion, which is reflected in the Predecessor Company’s results of operations for the period January 1, 2003 through December 5, 2003. The application of the Fresh Start provisions of SOP 90-7 created a new reporting entity having no retained earnings or accumulated deficit.

     As part of the bankruptcy process we engaged an independent financial advisor to assist in the determination of our reorganized enterprise value. The fair value calculation was based on management’s forecast of expected cash flows from our core assets. Management’s forecast incorporated forward commodity market prices obtained from a third party consulting firm. A discounted cash flow calculation was used to develop the enterprise value of Reorganized NRG, determined in part by calculating the weighted average cost of capital of the Reorganized NRG. The Discounted Cash Flow, or “DCF”, valuation methodology equates the value of an asset or business to the present value of expected future economic benefits to be generated by that asset or business. The DCF methodology is a “forward looking” approach that discounts expected future economic benefits by a theoretical or observed discount rate. The independent financial advisors prepared a 30-year cash flow forecast using a discount rate of approximately 11%. The resulting reorganization enterprise value as included in the Disclosure Statement ranged from $5.5 billion to $5.7 billion. The independent financial advisor then subtracted our project level debt and made several other adjustments to reflect the values of assets held for sale, excess cash and collateral requirements to estimate a range of Reorganized NRG equity value of between $2.2 billion and $2.6 billion.

     In constructing our Fresh Start balance sheet upon our emergence from bankruptcy we used a reorganization equity value of approximately $2.4 billion, as we believe this value to be the best indication of the value of the ownership distributed to the new equity owners. Our NRG Plan of reorganization provided for the issuance of 100,000,000 shares of NRG common stock to the various creditors resulting in a calculated price per share of $24.04. Our reorganization value of approximately $9.1 billion was determined by adding our reorganized equity value of $2.4 billion, $3.7 billion of interest bearing debt and our other liabilities of $3.0 billion. The reorganization value represents the fair value of an entity before liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after restructuring. This value is consistent with the voting creditors and bankruptcy court’s approval of the NRG plan of reorganization.

     We recorded approximately $4.1 billion of net reorganization income in the Predecessor Company’s statement of operations for 2003, which includes the gain on the restructuring of equity and the discharge of obligations subject to compromise for less than recorded amounts, as well as adjustments to the historical carrying values of our assets and liabilities to fair market value.

     Due to the adoption of Fresh Start as of December 5, 2003, the Reorganized NRG post-Fresh Start balance sheet, statement of operations and statement of cash flows have not been prepared on a consistent basis with the Predecessor Company’s financial statements and are therefore not comparable in certain respects to the financial statements prior to the application of Fresh Start. A black line has been drawn on the accompanying Consolidated Financial Statements to separate and distinguish between Reorganized NRG and the Predecessor Company. The effects of the reorganization and Fresh Start on our balance sheet as of December 5, 2003, were as follows (in thousands):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Reorganized	
 	 	Company	 	Debt Discharge	 	 	 	 	 	 	 	 	 	 	 	 	 	NRG	
 	 	December 5,	 	and Exchange	 	 	 	 	 	 	 	 	 	 	 	 	 	December 6,	
 	 	2003

	 	of Stock

	 	Fresh Start Adjustments

	 	Consolidation

	 	2003

	
 	 	 	 	 	 	 	 	 	 	(In thousands)	 	 	 	 	 	 	 	 	
Current Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	396,018	 	 	$	(1,728	)(B)	 	$	 	 	 	$	 	 	 	$	1,692	(T)	 	$	395,982	 	
Restricted cash	 	 	489,383	 	 	 	1,732	(B)	 	 	 	 	 	 	 	 	 	 	1,932	(T)	 	 	493,047	 	
Accounts receivable — trade	 	 	208,677	 	 	 	 	 	 	 	(2	)(B)	 	 	3,627	(J)	 	 	1,177	(T)	 	 	213,479	 	
Accounts receivable — affiliates	 	 	41,259	 	 	 	 	 	 	 	819	(B)	 	 	(42,078	)(J)	 	 	 	 	 	 	—	 	
Xcel Energy settlement receivable	 	 	 	 	 	 	640,000	(A)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	640,000	 	
Current portion of notes receivable	 	 	66,628	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	66,628	 	
Inventory	 	 	233,185	 	 	 	 	 	 	 	(25,945	)(K)	 	 	(11,004	)(L)	 	 	 	 	 	 	196,236	 	
Derivative instruments valuation	 	 	161	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	161	 	
Prepayments and other current assets	 	 	156,841	 	 	 	(25,855	)(B)	 	 	(7,309	)(M)	 	 	85,873	(J)	 	 	1,047	(T)	 	 	210,597	 	
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 	 	Predecessor	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Reorganized	
 	 	Company	 	Debt Discharge	 	 	 	 	 	 	 	 	 	 	 	 	 	NRG	
 	 	December 5,	 	and Exchange	 	 	 	 	 	 	 	 	 	 	 	 	 	December 6,	
 	 	2003

	 	of Stock

	 	Fresh Start Adjustments

	 	Consolidation

	 	2003

	
 	 	 	 	 	 	 	 	 	 	(In thousands)	 	 	 	 	 	 	 	 	
Current assets — discontinued operations	 	 	126,132	 	 	 	 	 	 	 	(1,241	)(K)	 	 	1,629	(J)	 	 	 	 	 	 	126,520	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total current assets	 	 	1,718,284	 	 	 	614,149	 	 	 	(33,678	)	 	 	38,047	 	 	 	5,848	 	 	 	2,342,650	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Property, Plant and Equipment	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net property, plant and equipment	 	 	5,247,375	 	 	 	 	 	 	 	(1,153,101	)(I)	 	 	(132,128	)(J)	 	 	46,652	(T)	 	 	4,008,798	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Other Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Equity investments in affiliates	 	 	956,757	 	 	 	 	 	 	 	(216,029	)(C)	 	 	14	(J)	 	 	(6,880	)(T)	 	 	733,862	 	
Notes receivable, less current portion — affiliates	 	 	164,987	 	 	 	 	 	 	 	(39,336	)(P)	 	 	 	 	 	 	 	 	 	 	125,651	 	
Notes receivable, less current portion	 	 	752,847	 	 	 	(155,477	)(D)	 	 	77,862	(P)	 	 	 	 	 	 	(301	)(T)	 	 	674,931	 	
Decommissioning fund investments	 	 	4,787	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	4,787	 	
Intangible assets, net	 	 	70,275	 	 	 	 	 	 	 	437,222	(O)	 	 	(22,829	)(I)	 	 	 	 	 	 	484,668	 	
Debt issuance cost, net	 	 	67,045	 	 	 	 	 	 	 	(67,045	)(P)	 	 	 	 	 	 	 	 	 	 	—	 	
Derivative instruments valuation	 	 	66,442	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	66,442	 	
Other assets, net	 	 	18,268	 	 	 	 	 	 	 	(37,891	)(P)	 	 	98,857	(J)	 	 	2,170	(T)	 	 	112,890	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	31,486	(J)	 	 	 	 	 	 	 	 	
Non-current assets — discontinued operations	 	 	822,569	 	 	 	 	 	 	 	(209,919	)(P)	 	 	 	 	 	 	 	 	 	 	612,650	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total other assets	 	 	2,923,977	 	 	 	(155,477	)	 	 	(55,136	)	 	 	107,528	 	 	 	(5,011	)	 	 	2,815,881	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total Assets	 	$	9,889,636	 	 	$	458,672	 	 	$	(1,241,915	)	 	$	13,447	 	 	$	47,489	 	 	$	9,167,329	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Current Liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current portion of long-term debt	 	$	1,433,551	 	 	$	(155,477	)(D)	 	$	(89,182	)(P)	 	$	1,307,249	(Q)	 	$	613	(T)	 	$	2,496,754	 	
Short-term debt	 	 	 	 	 	 	 	 	 	 	18,645	(P)	 	 	 	 	 	 	 	 	 	 	18,645	 	
Accounts payable — trade	 	 	299,409	 	 	 	(101,632	)(E)	 	 	(805	)(N)	 	 	5,499	(J)	 	 	 	 	 	 	202,471	 	
Accounts payable — affiliates	 	 	21,457	 	 	 	(2,308	)(B)	 	 	(5,192	)(N)	 	 	2,995	(J)	 	 	36	(T)	 	 	16,988	 	
Accrued income tax	 	 	19,303	 	 	 	 	 	 	 	(7,127	)(M)	 	 	4,255	(J)	 	 	 	 	 	 	16,431	 	
Accrued property, sales and other taxes	 	 	30,200	 	 	 	 	 	 	 	(5,942	)(B)	 	 	3,556	(J)	 	 	 	 	 	 	27,814	 	
Accrued salaries, benefits and related costs	 	 	14,195	 	 	 	 	 	 	 	 	 	 	 	2,519	(J)	 	 	5	(T)	 	 	16,719	 	
Accrued interest	 	 	76,485	 	 	 	(2,464	)(B)	 	 	 	 	 	 	1,631	(J)	 	 	121	(T)	 	 	75,773	 	
Derivative instruments valuation	 	 	95	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	95	 	
Creditor pool obligation	 	 	 	 	 	 	1,040,000	(F)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	1,040,000	 	
Other bankruptcy settlement	 	 	 	 	 	 	220,000	(F)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	220,000	 	
Other current liabilities	 	 	135,275	 	 	 	57	(F)	 	 	11,800	(O)	 	 	(10,770	)(J)	 	 	413	(T)	 	 	136,775	 	
Current liabilities — discontinued operations	 	 	160,648	 	 	 	 	 	 	 	(51,679	)(J)	 	 	6	(J)	 	 	 	 	 	 	108,975	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total Current Liabilities	 	 	2,190,618	 	 	 	998,176	 	 	 	(129,482	)	 	 	1,316,940	 	 	 	1,188	 	 	 	4,377,440	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Other Liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term debt	 	 	849,192	 	 	 	10,000	(G)	 	 	(21,869	)(P)	 	 	303	(J)	 	 	42,060	(T)	 	 	879,686	 	
Deferred income taxes	 	 	146,120	 	 	 	 	 	 	 	(13,973	)(M)	 	 	12,541	(J)	 	 	 	 	 	 	144,688	 	
Postretirement and other benefit obligations	 	 	44,601	 	 	 	(1,118	)(B)	 	 	64,067	(R)	 	 	(2,838	)(J)	 	 	 	 	 	 	104,712	 	
Derivative instruments valuation	 	 	53,082	 	 	 	 	 	 	 	 	 	 	 	102,627	(J)	 	 	 	 	 	 	155,709	 	
Other long-term obligations	 	 	146,761	 	 	 	763	(B)	 	 	488,218	(O)	 	 	(99,060	)(J)	 	 	 	 	 	 	536,682	 	
Non-current liabilities — Discontinued operations	 	 	558,194	 	 	 	 	 	 	 	1,366	(M)	 	 	 	 	 	 	 	 	 	 	559,560	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total non-current liabilities	 	 	1,797,950	 	 	 	9,645	 	 	 	517,809	 	 	 	13,573	 	 	 	42,060	 	 	 	2,381,037	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total liabilities not subject to compromise	 	 	3,988,568	 	 	 	1,007,821	 	 	 	388,327	 	 	 	1,330,513	 	 	 	43,248	 	 	 	6,758,477	 	
Total liabilities subject to compromise	 	 	7,658,071	 	 	 	(6,278,547	)(H)	 	 	(1,367	)(J)	 	 	(1,378,157	)(Q)	 	 	 	 	 	 	—	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total liabilities	 	 	11,646,639	 	 	 	(5,270,726	)	 	 	386,960	 	 	 	(47,644	)	 	 	43,248	 	 	 	6,758,477	 	
Stockholders’ Equity/(Deficit)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Minority interest	 	 	611	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	4,241	(T)	 	 	4,852	 	
Commitments and Contingencies	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Class A — Common stock; $.01 par value; 100 shares authorized in 2002; 3 shares issued and outstanding at December 31, 2002	 	 	1	 	 	 	(1	)(S)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	—	 	
Common stock; $.01 par value; 100 authorized in 2002; 1 share issued and outstanding at December 31, 2002	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	—	 	
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Table of Contents
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Reorganized	
 	 	Company	 	Debt Discharge	 	 	 	 	 	 	 	 	 	 	 	 	 	NRG	
 	 	December 5,	 	and Exchange	 	 	 	 	 	 	 	 	 	 	 	 	 	December 6,	
 	 	2003

	 	of Stock

	 	Fresh Start Adjustments

	 	Consolidation

	 	2003

	
 	 	 	 	 	 	 	 	 	 	(In thousands)	 	 	 	 	 	 	 	 	
Common stock; $.01 par value; 500,000,000 authorized in 2003; 100,000,000 shares issued and outstanding at December 6, 2003	 	 	—	 	 	 	1,000	(H)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	1,000	 	
Additional paid-in capital	 	 	2,227,691	 	 	 	2,403,000	(H)	 	 	(2,227,691	)	(S)	 	 	 	 	 	 	 	 	 	2,403,000	 	
Retained earnings/(deficit)	 	 	(3,986,739	)	 	 	 	 	 	 	3,924,215	 	(S)	 	62,524	 	(S)	 	 	 	 	 	—	 	
Accumulated other comprehensive income	 	 	1,433	 	 	 	 	 	 	 	 	 	 	 	(1,433	)	(S)	 	 	 	 	 	—	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total Stockholders’ equity/ (deficit)	 	 	(1,757,614	)	 	 	2,403,999	 	 	 	1,696,524	 	 	 	61,091	 	 	 	 	 	 	 	2,404,000	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total Liabilities and Stockholders’ Equity/ (Deficit)	 	$	9,889,636	 	 	$	(2,866,727	)	 	$	2,083,484	 	 	$	13,447	 	 	$	47,489	 	 	$	9,167,329	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	

	 	 	
 	
(A)	 	Represents a $640.0 million receivable from Xcel Energy that relates to the Xcel Energy Settlement Agreement. $288.0 million was paid on February 20, 2004 in cash and $352.0 million will be paid on April 30, 2004.	 	 	
 	
(B)	 	Adjustments to assets and liabilities resulting from the NRG Energy bankruptcy settlement.	 	 	
 	
(C)	 	Includes the adjustment of carrying amount of Investments in Projects to fair market value as determined by independent appraisers.	 	 	
 	
(D)	 	The NRG Energy bankruptcy settlement included the liquidation of NRG FinCo. As a result, the NRG FinCo creditors obtained a perfected first priority security interest in all of LSP Pike Energy LLC assets, making the Mississippi Industrial Revenue Bonds owed by LSP Pike Energy LLC worthless.	 	 	
 	
(E)	 	Includes $103.0 million discharge of obligations related to LSP Pike Energy LLC settlement with Shaw Constructors, Inc.	 	 	
 	
(F)	 	Includes the establishment of a creditor’s pool and the FinCo lender settlement (in millions):	 	 	

Creditor installment payments	 	$	515.0	 	
Establishment of Plan of reorganization liability	 	 	500.0	 	
Contingency payment	 	 	25.0	 	
FinCo lender settlement (see Note 24)	 	 	220.0	 	

 	 	
Total other current liabilities	 	$	1,260.0	 	

 	 	

(G)	 	Represents NRG Energy Promissory Note owed to Xcel Energy, due June 5, 2006 with a stated interest rate of 3.0%	 	 	
 	
(H)	 	Represents the elimination of approximately $5.2 billion of corporate level bank and bond debt and approximately $1.1 billion of additional claims and disputes by distributing a combination of equity and up to $1.04 billion in cash among our unsecured creditors. Upon reorganization we issued 100 million shares of NRG common stock at $24.04 per share.	 	 	

(I)	 	Result of allocating the reorganization value in conformity with the purchase method of accounting for business combinations. These allocations were based on valuations obtained from independent appraisers.	 	 	
 	
(J)	 	Adoption of Fresh Start Reporting and reinstatement of miscellaneous liabilities subject to compromise.	 	 	
 	
(K)	 	Accounting policy change upon adoption of fresh start reporting. Consumables are no longer included as inventory and are expensed as incurred.	 	 	
 	
(L)	 	Accounting policy change upon adoption of fresh start reporting. Capital spares were reclassified from inventory to Property Plant and Equipment.	 	 	
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(M)	 	Records income taxes of the Company based on the guidance provided in the Statement of Financial Accounting Standards No. 109 and SOP 90-7.	 	 	
 	
(N)	 	Adjust assets and liabilities to reflect management’s estimate, with the assistance of independent specialists, of the fair value.	 	 	

(O)	 	Reflects management’s estimate, with the assistance of independent appraisers, of the fair value of power purchase agreements and SO(2) emission credits. Management identified certain power purchase agreements that were either significantly valuable or significantly burdensome as compared to our market expectations. The predecessor goodwill and intangibles were written off. Our guarantees were reviewed for the requirement to recognize a liability at inception. As a result, we recorded a $15.0 million liability. In addition, our Asset Retirement Obligation or “ARO” was revalued.	

 	 	(In millions)	
SO(2) emission credits	 	$	373.5	 	
Valuable contracts	 	 	111.2	 	
Predecessor intangible	 	 	(47.5	)	

 	 	
Total intangible	 	$	437.2	 	

 	 	
Burdensome contracts	 	$	15.1	 	
Other valuations adjustments	 	 	(3.3	)	

 	 	
Total other current liabilities	 	$	11.8	 	

 	 	
Burdensome contracts	 	$	467.2	 	
Other valuations adjustments	 	 	21.0	 	

 	 	
Total other long-term obligations	 	$	488.2	 	

 	 	

(P)	 	Reflects management’s estimate, based on current market interest rates as of December 5, 2003, of the fair value of notes receivable, notes payable and other debt instruments.	

(Q)	 	Reclassification of subject to compromise liabilities due to emergence from bankruptcy consists primarily of the debt held at our Northeast and South Central subsidiaries of $1.3 billion. The remaining amounts were reclassified to current liabilities.	

(R)	 	Adjustment to post-retirement and other benefit obligations in order to reflect the accumulated benefit obligation liability based on independent actuarial reports. The pension and welfare plans were assumed from Xcel Energy without the transfer of assets.	

(S)	 	Reflects the cancellation of the Predecessor Company’s common stock and the elimination of the retained deficit and the accumulated other comprehensive loss.	

(T)	 	As required by SOP 90-7, we have adopted FASB Interpretation No. 46 “Consolidation of Variable Interest Entities,”  or “FIN 46,” as of the adoption of Fresh Start. The adoption of FIN 46 resulted in the consolidation of Northbrook New York, LLC and Northbrook Energy, LLC.	
     APB No. 18, “The Equity Method of Accounting for Investments in Common Stock,” requires us to effectively push down the effects of Fresh Start reporting to our unconsolidated equity method investments and to recognize an adjustment to our share of the earnings or losses of an investee as if the investee were a consolidated subsidiary. As a result of pushing down the impact of Fresh Start to our West Coast Power affiliate, we determined that a contract based intangible asset with a one year remaining life, consisting of the value of West Coast Power’s California Department of Water Resources energy sales contract, must be established and recognized as a basis adjustment to our share of the future earnings generated by West Coast Power. This adjustment will reduce our equity earnings in the amount of approximately $10.4 million per month until the contract expires in December 2004.

Liquidity and Capital Resources

     Reorganized Capital Structure

     In connection with the consummation of the NRG plan of reorganization, on December 5, 2003 all shares of our old common stock were canceled and 100,000,000 shares of new common stock of NRG Energy were distributed pursuant to such plan to the holders of certain classes of claims. A certain number of shares of common stock were issued for distribution to holders of disputed claims as such claims are resolved or settled. In the event our disputed claims reserve is inadequate, it is possible we would have to issue additional shares of our common stock to satisfy such pre-petition claims or contribute additional cash proceeds. See Item 3 — Legal

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Proceedings — Disputed Claims Reserve. Our authorized capital stock consists of 500,000,000 shares of NRG Energy common stock and 10,000,000 shares of Serial Preferred Stock. Further, a total of 4,000,000 shares of our common stock, representing approximately 4% of our outstanding common stock, are available for issuance under our long-term incentive plan.

     In addition to our issuance of new common stock, on December 23, 2003, we completed a note offering consisting of $1.25 billion of 8% Second Priority Senior Secured Notes due 2013, or the “Second Priority Notes”, and we entered into a new credit facility consisting of a $950.0 million term loan facility, a $250.0 million funded letter of credit facility and a $250.0 million revolving credit facility. In January of 2004, we completed a supplementary note offering whereby we issued an additional $475.0 million of the Second Priority Notes at a premium and used the proceeds to repay a portion of the $950.0 million term loan. As of March 1, 2004, we had $1.7 billion in aggregate principal amount of Second Priority Notes outstanding, $446.5 million principal amount outstanding under the term loan and $147.5 million remains available under the funded letter of credit facility. As of March 1, 2004, we had not drawn down on our revolving credit facility. Finally, in connection with the consummation of the NRG plan of reorganization, we issued to Xcel Energy a $10.0 million non-amortizing promissory note, which will accrue interest at a rate of 3% per annum and mature 2.5 years after the effective date of the NRG plan of reorganization.

     As part of the NRG plan of reorganization, we eliminated approximately $5.2 billion of corporate level bank and bond debt and approximately $1.3 billion of additional claims and disputes through our distribution of new common stock and $1.04 billion in cash among our unsecured creditors. In addition to the debt reduction associated with the restructuring, we used the proceeds of the recent note offering and borrowings under the New Credit Facility to retire approximately $1.7 billion of project-level debt.

     For additional information on our short term and long term borrowing arrangements, see Item 15 — Note 17 to the Consolidated Financial Statements.

     Historical Cash Flows

     Predecessor Company

     Historically, we have obtained cash from operations, issuance of debt and equity securities, borrowings under credit facilities, capital contributions from Xcel Energy, reimbursement by Xcel Energy of tax benefits pursuant to a tax sharing agreement and proceeds from non-recourse project financings. We used these funds to finance operations, service debt obligations, fund the acquisition, development and construction of generation facilities, finance capital expenditures and meet other cash and liquidity needs.

Reorganized NRG

     We have obtained cash from operations, Xcel Energy’s contribution net of distributions to creditors, proceeds from the sale of certain assets and borrowings under our Second Priority Notes and New Credit Facility.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor Company

	 	Reorganized NRG

	
 	 	Year Ended December 31,

	 	For the Period
January 1 -
December 5,	 	For the Period
December 6 -
December 31,	
 	 	2001

	 	2002

	 	2003

	 	2003

	
 	 	(In thousands)	
Net cash provided (used) by operating activities	 	$	276,014	 	 	$	430,042	 	 	$	238,509	 	 	$	(588,875	)	
Net cash (used) provided by investing activities	 	 	(4,335,641	)	 	 	(1,681,467	)	 	 	(185,679	)	 	 	363,372	 	
Net cash provided (used) by financing activities	 	 	4,153,546	 	 	 	1,449,330	 	 	 	(29,944	)	 	 	393,273	 	
     Net Cash Provided (Used) By Operating Activities

     Predecessor Company

     Net cash provided by operating activities increased during 2002 compared with 2001, primarily due to our efforts to conserve cash by deferring the payment of interest and managing our cash flows more closely. As a result, we increased accounts payable and accrued interest balances and reduced inventory levels.

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     For the period January 1, 2003 through December 5, 2003 net cash provided by operating activities was $238.5 million. Operating activities consisted of a net loss before Fresh Start adjustments of $1.1 billion, offset by non-cash charges of $567.5 million and cash provided by working capital of $800.1 million. The non-cash charges consisted primarily of the write-down of our investment in Loy Yang, asset impairments and legal settlement charges. The favorable change in working capital was primarily due to reduced cash expenditures throughout the bankruptcy period resulting in increased accounts payable.

     Reorganized NRG

     For the period December 6, 2003 through December 31, 2003 cash used by operating activities was $588.9 million. This was primarily a result of payments made to creditors upon our emergence from bankruptcy.

     Net Cash Provided (Used) By Investing Activities

     Predecessor Company

     Net cash used in investing activities decreased in 2002, compared with 2001, primarily as a result of the termination of our acquisition program due to our financial difficulties and the receipt of cash upon the sale of assets during 2002.

     For the period January 1, 2003 through December 5, 2003 cash used in investing activities $185.7 million. This was primarily a result of capital expenditures and an increase in restricted cash, offset by cash proceeds received upon the sale of investments.

     Reorganized NRG

     For the period December 6, 2003 through December 31, 2003 cash provided by investing activities was $363.4 million. In connection with the refinancing transaction, approximately $375.3 million of restricted cash was released upon payment of the Northeast Generating and South Central Generating note. This increase was offset by funds used for capital expenditures and investments in projects.

     Net Cash Provided (Used) By Financing Activities

     Predecessor Company

     Net cash provided by financing activities decreased during 2002 compared to 2001 due to constraints on our ability to access the capital markets and the cancellation and termination of construction projects reducing the need for capital.

     For the period January 1, 2003 through December 5, 2003 cash used by financing activities was $29.9 million, which consisted primarily of principal payments offset by the issuance of additional debt.

     Reorganized NRG

     For the period December 6, 2003 through December 31, 2003 cash provided by financing activities was $393.3 million. We entered into refinancing transactions on December 23, 2003, where we issued $1.25 billion of Second Priority Notes and entered into the New Credit Facility, which consisted of a $950.0 million senior secured term loan facility and a $250.0 million funded letter of credit facility. Upon completion of the refinancing transactions, we repaid the Northeast Generating and South Central Generating notes and the Mid-Atlantic Generating obligations.

     Sources of Funds

     The principal sources of liquidity for our future operations, capital expenditures, facility closures and project restructurings are expected to be: (i) existing cash on hand and cash flows from operations, (ii) Xcel Energy’s contribution net of distributions to creditors, (iii) proceeds from the sale of certain assets and businesses and (iv) borrowings under our New Credit Facility, including up to $250.0 million of available borrowings under our new revolving credit facility and up to $250.0 million of a pre-funded letter of credit facility. Additionally, there are approximately $89.5 million of undrawn letters of credit under the pre-petition ANZ LC Facility. The ANZ LC Facility is supported by a cash funded claim reserve to support any letters of credit drawn prior to their expiration.

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Capacity under the ANZ LC facility will be reduced as the underlying LCs expire or are terminated. All of the LCs will expire or be terminated by the end of 2004, at which time the ANZ LC facility will no longer exist.

     As a result of our emergence from bankruptcy, all of our then existing securities, including our old common stock and various issuances of senior notes, were cancelled and approximately $5.2 billion of our existing debt and approximately $1.3 billion of additional claims and disputes were eliminated for a combination of equity and up to $1.04 billion in cash.

     On December 23, 2003, we entered into a bank facility for up to $1.45 billion, or the “New Credit Facility”, which included a $950.0 million, six and a half-year senior secured term loan, a $250.0 million funded letter of credit facility, and a four-year $250.0 million revolving line of credit, or the “revolving credit facility.” Portions of the revolving credit facility are available as a swing-line facility and as a revolving letter of credit sub-facility. As of December 31, 2003, the corporate revolver was undrawn. Also on December 23, 2003, we issued $1.25 billion in 8% second priority, senior secured notes, or the “Second Priority Notes”, due and payable on December 15, 2013.

     Upon completion of the refinancing transactions, we, among other things: (i) repaid the Northeast Generating LLC Notes, or “Northeast Notes”, the South Central Generating LLC Notes, or “South Central Notes”, and the Mid-Atlantic Generating LLC Obligations; (ii) paid a settlement amount associated with the repayment of the Northeast Notes and the South Central Notes; (iii) paid $500.0 million in lieu of 10% NRG Energy senior notes to former unsecured creditors pursuant to the NRG plan of reorganization, the “POR Notes”, (see the discussion of Senior Securities under Item 15 — Note 17 to the Consolidated Financial Statements) ; (iv) pre-funded a letter of credit sub-facility under the New Credit Facility in the amount of $250.0 million; and (v) paid fees and expenses related to the offering of notes and the New Credit Facility in the amount of $74.8 million.

     On January 28, 2004, we issued an additional $475.0 million of the Second Priority Notes, obtaining net proceeds of $501.8 million. With proceeds from this issuance and other funds, we subsequently 1) repaid $503.5 million of the term loan under the New Credit Facility, reducing the principal outstanding from $950.0 million to $446.5 million, 2) made a prepayment premium payment of $15.1 million, and 3) repaid accrued but unpaid interest on the prepayment amount, totaling $0.4 million. On February 25, 2004, we received from our term loan lenders a waiver under the New Credit Facility waiving our obligation to enter into a hedge arrangement on a notional value of $500.0 million, as required by the credit agreement.

     Cash Flows. Our operating cash flows are expected to be impacted by, among other things: (i) spark spreads generally; (ii) commodity prices (including demand for natural gas, coal, oil and electricity); (iii) the cost of ordinary course operations and maintenance expenses; (iv) planned and unplanned outages; (v) contraction of terms by trade creditors; (vi) cash requirements for closure and restructuring of certain facilities; (vii) restrictions in the declaration or payments of dividends or similar distributions from our subsidiaries; and (viii) the timing and nature of asset sales.

     A principal component of the NRG plan of reorganization is a settlement with Xcel Energy in which Xcel Energy agreed to make a contribution to us consisting of cash (and, under certain circumstances, its common stock) in an aggregate amount of up to $640.0 million to be paid in three separate installments. Xcel Energy contributed $288.0 million on February 20, 2004. We anticipate receiving an additional installment of up to $352.0 million in cash on April 30, 2004. We will distribute $515.0 million of cash we receive from Xcel Energy to our creditors. In the event we achieve certain liquidity measures in September 2004, an additional $25.0 million may be distributed to creditors, and we may use $100.0 million for any purpose, subject to any restrictions contained in the indenture or the New Credit Facility.

     Asset Sales. We received $229.3 million and $196.2 million in net cash proceeds from the sale of certain assets and businesses in the fiscal years ended 2002 and 2003, respectively. The New Credit Facility and the indenture governing the notes place restrictions on the use of any proceeds we may receive from certain asset sales in the future.

     Letter of Credit Sub-facility and Revolving Credit Facility. The New Credit Facility includes a letter of credit sub-facility in the amount of $250.0 million. As of December 31, 2003, we had issued $1.7 million in letters of credit under this facility. The New Credit Facility also includes a revolving credit facility in the amount of $250.0 million to be used for general corporate purposes. On December 31, 2003 we had not yet drawn on our revolving credit facility. For additional information regarding our debt see Item 15 — Note 17 to the Consolidated Financial Statements.

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Table of Contents

     Uses of Funds

     Our requirements for liquidity and capital resources, other than for operating our facilities, can generally be categorized by the following: (i) PMI activities; (ii) capital expenditures; and (iii) project finance requirements for cash collateral.

     PMI. PMI activities comprise the single largest requirement for liquidity and capital resources. PMI liquidity requirements are primarily driven by: (i) margin and collateral posting requirements with counterparties; (ii) establishment of trading relationships; (iii) disbursement and receipt timing (i.e., buying fuel before receiving energy revenues); and (iv) initial collateral for large structured transactions. For 2004, we believe that approximately $265 million to $360 million may be required for PMI to meet potential margin requirements and to cover prepayments and fuel inventory builds.

     Estimates for liquidity requirements are highly dependent on our hedging activity and then current market conditions, including forward prices for energy and fuel and market volatility. In addition, our estimates are dependent on credit terms with third parties. We do not assume that we will be provided with unsecured credit from third parties in budgeting our working capital requirements.

     Capital Expenditures. Capital expenditures were $1.4 billion for the year ended 2002, $113.5 million for the period January 1, 2003 through December 5, 2003 and $10.6 million for the period December 6, 2003 through December 31, 2003. Capital expenditures in 2003 relate primarily to operations and maintenance of our existing generating facilities whereas capital expenditures in 2002 related primarily to new plant construction. We anticipate that our 2004 capital expenditures will be approximately $113.8 million and will relate primarily to the operation and maintenance of our existing generating facilities.

     Project Finance Requirements. We are a holding company and conduct our operations through subsidiaries. Historically, we have utilized non-recourse debt to fund a significant portion of the capital expenditures and investments required to construct our power plants and related assets. Consistent with our strategy, we may seek, where available on commercially reasonable terms, non-recourse debt financing in connection with the assets or businesses that our affiliates or we may develop, construct or acquire. Non- recourse borrowings are substantially non-recourse to other subsidiaries, affiliates and us, and are generally secured by the capital stock, physical assets, contracts and cash flow of the related project subsidiary or affiliate. Some of these project financings require us to post collateral in the form of cash or an acceptable letter of credit.

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Table of Contents

     Principal on short-term debt, long-term debt and capital leases as of December 31, 2003 are due and payable in the following periods (in thousands):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Subsidiary/Description

	 	Total

	 	2004

	 	2005

	 	2006

	 	2007

	 	2008

	 	Thereafter

	
$250 Million Revolver Due Dec 2007	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	
Xcel Energy Note	 	 	10,000	 	 	 	—	 	 	 	—	 	 	 	10,000	 	 	 	 	 	 	 	—	 	 	 	—	 	
Credit Facility Due June 2010	 	 	1,200,000	 	 	 	12,000	 	 	 	12,000	 	 	 	12,000	 	 	 	12,000	 	 	 	12,000	 	 	 	1,140,000	 	
8% Senior Secured Notes due Dec. 2013	 	 	1,250,000	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1,250,000	 	
MEC Corp.	 	 	126,279	 	 	 	7,329	 	 	 	7,876	 	 	 	8,465	 	 	 	9,097	 	 	 	9,777	 	 	 	83,735	 	
NRG Peaker Finance Co LLC	 	 	311,373	 	 	 	311,373	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
LSP — Kendall Energy	 	 	487,013	 	 	 	487,013	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Flinders Power Finance Pty	 	 	187,668	 	 	 	—	 	 	 	9,292	 	 	 	12,436	 	 	 	13,538	 	 	 	14,737	 	 	 	137,665	 	
Pittsburgh Thermal LP	 	 	1,550	 	 	 	1,550	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
San Francisco Thermal LP	 	 	860	 	 	 	729	 	 	 	31	 	 	 	34	 	 	 	37	 	 	 	29	 	 	 	—	 	
Meridan	 	 	500	 	 	 	500	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Camas Pwr BLR LP Bank facility	 	 	8,628	 	 	 	2,352	 	 	 	2,443	 	 	 	2,533	 	 	 	1,300	 	 	 	—	 	 	 	—	 	
Camas Pwr BLR LP Bonds	 	 	5,765	 	 	 	1,290	 	 	 	1,385	 	 	 	1,485	 	 	 	1,605	 	 	 	—	 	 	 	—	 	
Northbrook New York	 	 	17,199	 	 	 	300	 	 	 	500	 	 	 	600	 	 	 	700	 	 	 	800	 	 	 	14,299	 	
Northbrook Carolina	 	 	2,475	 	 	 	100	 	 	 	100	 	 	 	100	 	 	 	150	 	 	 	150	 	 	 	1,875	 	
Northbrook STS HydroPower	 	 	24,506	 	 	 	436	 	 	 	477	 	 	 	523	 	 	 	572	 	 	 	627	 	 	 	21,871	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Subtotal Debt, Bonds and Notes	 	 	3,633,816	 	 	 	824,972	 	 	 	34,104	 	 	 	48,176	 	 	 	38,999	 	 	 	38,120	 	 	 	2,649,445	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Saale Energie GmbH, Schkopau (capital lease)	 	 	342,469	 	 	 	75,944	 	 	 	78,580	 	 	 	43,858	 	 	 	33,075	 	 	 	27,039	 	 	 	83,973	 	
Audrain Generating (capital lease)	 	 	239,930	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	239,930	 	
NRG Processing Solutions, LLC (capital lease)	 	 	326	 	 	 	326	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Subtotal Capital Leases	 	 	582,725	 	 	 	76,270	 	 	 	78,580	 	 	 	43,858	 	 	 	33,075	 	 	 	27,039	 	 	 	323,903	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Itiquira	 	 	19,019	 	 	 	19,019	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Discontinued Operations	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
LSP Energy LP (Batesville)	 	 	307,175	 	 	 	7,575	 	 	 	9,600	 	 	 	11,925	 	 	 	12,525	 	 	 	12,825	 	 	 	252,725	 	
Hsin Yu Energy Development	 	 	85,300	 	 	 	85,300	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
PERC (Bonds)	 	 	26,265	 	 	 	1,735	 	 	 	1,820	 	 	 	1,910	 	 	 	2,005	 	 	 	2,110	 	 	 	16,685	 	
Cobee	 	 	31,800	 	 	 	11,025	 	 	 	11,535	 	 	 	4,620	 	 	 	4,620	 	 	 	—	 	 	 	—	 	
McClain	 	 	156,509	 	 	 	156,509	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Subtotal Discontinued Operations	 	 	607,049	 	 	 	262,144	 	 	 	22,955	 	 	 	18,455	 	 	 	19,150	 	 	 	14,935	 	 	 	269,410	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total Debt	 	$	4,842,609	 	 	$	1,182,405	 	 	$	135,639	 	 	$	110,489	 	 	$	91,224	 	 	$	80,094	 	 	$	3,242,758	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
     Principal payments for debt that have been deemed current for financial reporting purposes as of December 31, 2003 are reflected as short-term in the table above. Events may have occurred since December 31, 2003 that would allow such debt to be paid on a normal amortizing schedule. Prepayments, or additional borrowing under certain facilities, since December 31, 2003 are not reflected. See Item 15 — Note 17 to the Consolidated Financial Statements for further discussion on events that may affect debt payment schedules.

     If we decide not to provide any additional funding or credit support to our subsidiaries, the inability of any of our subsidiaries that are under construction or that have near-term debt payment obligations to obtain non- recourse project financing may result in such subsidiary’s insolvency and the loss of our investment in such subsidiary. Additionally, the loss of a significant customer at any of our subsidiaries may result in the need to restructure the non-recourse project financing at that subsidiary, and the inability to successfully complete a restructuring of the non-recourse project financing may result in a loss of our investment in such subsidiary. Certain of our projects are subject to restrictions regarding the movement of cash. For additional information see Item 15 — Note 17 to the Consolidated Financial Statements.

     Liquidity Estimates

     For 2004, we anticipate utilizing all of our $250.0 million letter of credit sub-facility. In addition, we believe that approximately $265.0 million to $360.0 million of cash may be required for PMI to meet its potential margin requirements and to cover prepayments and fuel inventory builds. As part of our refinancing transactions, we have established a $250.0 million revolving credit facility. The revolving credit facility was established to satisfy short-term working capital requirements, which may arise from time to time. It is not our current intention to draw funds under the revolving credit facility.

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     Other Liquidity Matters

     We maintain cash deposits in order to assure the continuation of vendor trade terms. As of December 31, 2003, the total amount of cash deposits maintained for these purposes was approximately $48.3 million.

     We expect our capital requirements to be met with existing cash balances, cash flows from operations, borrowings under our Second Priority Notes and New Credit Facility, and asset sales. We believe that our current level of cash availability and asset sales, along with our future anticipated cash flows from operations, will be sufficient to meet the existing operational and collateral needs of our business for the next 12 months. Subject to restrictions in our Second Priority Notes and our New Credit Facility, if cash generated from operations is insufficient to satisfy our liquidity requirements, we may seek to sell assets, obtain additional credit facilities or other financings and/or issue additional equity or convertible instruments. We cannot assure you, however, that our business will generate sufficient cash flow from operations, that currently anticipated cost savings and operating improvements will be realized on schedule or that future borrowings will be available to us under our credit facilities in an amount sufficient to enable us to pay our indebtedness, or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness, on or before maturity. We cannot assure you that we will be able to refinance any of our indebtedness, on commercially reasonable terms or at all. To service our indebtedness, we will require a significant amount of cash. Our ability to generate cash depends on many factors beyond our control.

Net Operating Loss Carryforwards

     During 2002 and 2003 we generated a net operating loss carryforward of $1.0 billion which will expire in 2023. We have assessed the likelihood that a substantial portion of the deferred tax assets relating to the net operating loss carryforwards would not be realized. This assessment included consideration of positive and negative factors, including our current financial position and results of operations, projected future taxable income, including projected operating and capital gains, and available tax planning strategies. As a result of such assessment, we determined that it was more likely than not that the deferred tax assets related to our domestic net operating loss carryforwards would not be realized. Accordingly, a full valuation allowance was recorded against the net deferred tax assets including net operating loss carryforwards. We also determined that it is more likely than not that a substantial portion of the net operating loss generated in 2002 and 2003 could be determined to be capital in nature. Given that capital losses are of a different character than ordinary losses the likelihood of capital losses expiring unutilized is greater than that of ordinary net operating losses.

     In addition, the conversion of ordinary losses to capital losses, to the extent that the amount exceeds our existing net operating loss, results in a corresponding reduction to the tax basis of our fixed assets. The consequence of which is a reduction to expected depreciation in future years.

Off Balance-Sheet Items

     As of December 31, 2003, we do not have any significant relationships with structured finance or special purpose entities that provide liquidity, financing or incremental market risk or credit risk.

     We have numerous 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 as disclosed in Item 15 — Note 13 to the Consolidated Financial Statements. Our pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $967.7 million as of December 31, 2003. In the normal course of business we may be asked to loan funds to these entities on both a long and short-term basis. Such transactions are generally accounted for as accounts payables and receivables to/from affiliates and notes payables/receivables to/from affiliates and if appropriate, bear market-based interest rates. See Item 15 — Note 11 to the Consolidated Financial Statements for additional information regarding amounts accounted for as notes receivable — affiliates.

Contractual Obligations and Commercial Commitments

     We have a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to our capital expenditure programs. The following is a summarized table of contractual obligations. See additional discussion in Item 15 — Notes 17, 24 and 26 to the Consolidated Financial Statements.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Payments Due by Period as of December 31, 2003

	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	After	
Contractual Cash Obligations

	 	Total

	 	Short Term

	 	1-3 Years

	 	4-5 Years

	 	5 Years

	
 	 	(In thousands)	
Long-term debt **	 	$	3,633,816	 	 	$	824,972	 	 	$	82,280	 	 	$	77,119	 	 	$	2,649,445	 	
Capital lease obligations	 	 	582,725	 	 	 	76,270	 	 	 	122,438	 	 	 	60,114	 	 	 	323,903	 	
Operating leases***	 	 	45,625	 	 	 	8,760	 	 	 	14,799	 	 	 	7,132	 	 	 	14,934	 	
Creditor payments*	 	 	540,000	 	 	 	540,000	 	 	 	—	 	 	 	—	 	 	 	—	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total contractual cash obligations	 	$	4,802,166	 	 	$	1,450,002	 	 	$	219,517	 	 	$	144,365	 	 	$	2,988,282	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	

 	 	 	
 	 	 	
*	 	These amounts represent creditor payments under NRG’s plan of reorganization. Additionally, payments of up to $275 million will be required pursuant to security interests held in certain assets by creditors when the related assets are sold.	
 	 	 	
**	 	Long-term debt excludes debt recorded at our McClain, PERC, Cobee, LSP and Hsin Yu projects in the amounts of $156.5 million, $26.3 million, $31.8 million, $307.2 million and $85.3 million, respectively, which have been reclassified as discontinued operations.	
 	 	 	
***	 	Operating leases excludes obligations for operating leases at our Hsin Yu and Cobee projects in the amounts of $1.8 million and $0.1 million, respectively.	
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 	 	Amount of Commitment Expiration per Period as of	
 	 	December 31, 2003

	
 	 	Total	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Amounts	 	 	 	 	 	 	 	 	 	 	 	 	 	After	
Other Commercial Commitments

	 	Committed

	 	Short Term

	 	1-3 Years

	 	4-5 Years

	 	5 Years

	
 	 	(In thousands)	
Lines of credit	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	
Standby letters of credit	 	 	92,050	 	 	 	92,050	 	 	 	—	 	 	 	—	 	 	 	—	 	
Cash collateral calls	 	 	71,472	 	 	 	71,472	 	 	 	—	 	 	 	—	 	 	 	—	 	
Guarantees of Subsidiaries	 	 	506,935	 	 	 	—	 	 	 	19,490	 	 	 	778	 	 	 	486,667	 	
Guarantees of PMI	 	 	57,179	 	 	 	5,000	 	 	 	52,179	 	 	 	—	 	 	 	—	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total commercial commitments	 	$	727,636	 	 	$	168,522	 	 	$	71,669	 	 	$	778	 	 	$	486,667	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Interdependent Relationships

     We do not have any significant interdependent relationships. Since we formerly were an indirect wholly owned subsidiary of Xcel Energy, there were certain related party transactions that took place in the normal course of business. For additional information regarding our related party transactions, see Item 15 — Note 22 to the Consolidated Financial Statements.

Derivative Instruments

     We may enter into long-term power sales contracts, long-term 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.

     The tables below disclose the trading activities that include non-exchange traded contracts accounted for at fair value. Specifically, these tables disaggregate realized and unrealized changes in fair value; identify changes in fair value attributable to changes in valuation techniques; disaggregate estimated fair values at December 31, 2003 based on whether fair values are determined by quoted market prices or more subjective means; and indicate the maturities of contracts at December 31, 2003.

     Trading Activity Gains/(Losses)
 	 	 	 	 	 	 	 	 	
 	 	Predecessor	 	Reorganized	
 	 	Company

	 	NRG

	
 	 	(In thousands)	
Fair value of contracts at December 31, 2001	 	$	72,236	 	 	 	 	 	
Contracts realized or otherwise settled during the period	 	 	(119,061	)	 	 	 	 	
Other changes in fair value	 	 	77,465	 	 	 	 	 	

 	 	 	 	 	 	
Fair value of contracts at December 31, 2002	 	 	30,640	 	 	 	 	 	
Contracts realized or otherwise settled during the period	 	 	(187,603	)	 	 	 	 	
Other changes in fair value	 	 	112,865	 	 	 	 	 	

 	 	 	 	 	 	
Fair value of contracts at December 5, 2003	 	$	(44,098	)	 	 	 	 	
Fair value of contracts at December 6, 2003	 	 	 	 	 	$	(44,098	)	
Contracts realized or otherwise settled during the period	 	 	 	 	 	 	(2,390	)	
Other changes in fair value	 	 	 	 	 	 	(3,426	)	

 	 	
Fair value of contracts at December 31, 2003	 	 	 	 	 	$	(49,914	)	

 	 	
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     Sources of Fair Value Gains/(Losses)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG	
 	 	Fair Value of Contracts at Period End as of December 6, 2003

	
 	 	Maturity	 	 	 	 	 	 	 	 	 	Maturity	 	 	
 	 	Less than	 	Maturity	 	Maturity	 	in excess	 	Total Fair	
 	 	1 Year

	 	1-3 Years

	 	4-5 Years

	 	of 5 Years

	 	Value

	
 	 	 	 	 	 	 	 	 	 	(In thousands)	 	 	 	 	 	 	 	 	
Prices actively quoted	 	$	42,107	 	 	$	(7,022	)	 	$	(10,820	)	 	$	(68,363	)	 	$	(44,098	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
 	 	$	42,107	 	 	$	(7,022	)	 	$	(10,820	)	 	$	(68,363	)	 	$	(44,098	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	

 	 	Reorganized NRG	
 	 	Fair Value of Contracts at Period End as of December 31, 2003

	
 	 	Maturity	 	 	 	 	 	 	 	 	 	Maturity	 	 	
 	 	Less than	 	Maturity	 	Maturity	 	in excess	 	Total Fair	
 	 	1 Year

	 	1-3 Years

	 	4-5 Years

	 	of 5 Years

	 	Value

	
 	 	 	 	 	 	 	 	 	 	(In thousands)	 	 	 	 	 	 	 	 	
Prices actively quoted	 	$	34,462	 	 	$	(6,860	)	 	$	(8,570	)	 	$	(68,946	)	 	$	(49,914	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
 	 	$	34,462	 	 	$	(6,860	)	 	$	(8,570	)	 	$	(68,946	)	 	$	(49,914	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
     We may use a variety of financial instruments to manage our exposure to fluctuations in foreign currency exchange rates on our international project cash flows, interest rates on our cost of borrowing and energy and energy related commodities prices.

Critical Accounting Policies and Estimates

     Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. 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, we, evaluate our estimates, utilizing historic experience, consultation with experts and other methods we consider reasonable. In any case, actual results may differ significantly from our estimates. Any effects on our 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.

     Our significant accounting policies are summarized in Item 15 — Note 2 to the Consolidated Financial Statements. The following table identifies certain of the significant accounting policies listed in Item 15 — Note 2 to the Consolidated Financial Statements. The table also identifies the judgments required, uncertainties involved in the application of each and estimates that may have a material impact on our results of operations and statement of financial position. These policies, along with the underlying assumptions and judgments made by our management in their application, have a significant impact on our consolidated financial statements. We identify our most critical accounting policies as those that are the most pervasive and important to the portrayal of our financial position and results of operations, and that require the most difficult, subjective and/or complex judgments by management regarding estimates about matters that are inherently uncertain.
 	 	 	 	 	
Accounting Policy

	 	Judgments/ Uncertainties Affecting Application

	
Fresh Start Reporting	 	•	 	The determination of the enterprise value and the allocation to the underlying assets and liabilities are based on a number of estimates and assumptions, which are inherently subject to significant uncertainties and contingencies	
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Accounting Policy

	 	Judgments/ Uncertainties Affecting Application

	
 	 	•	 	Determination of enterprise value	
 	 	 	 	 	
 	 	•	 	Determination of Fresh Start date	
 	 	 	 	 	
 	 	•	 	Consolidation of entities remaining in bankruptcy	
 	 	 	 	 	
 	 	•	 	Valuation of emission credit allowances and power sales contracts	
 	 	 	 	 	
 	 	•	 	Valuation of debt instruments	
 	 	 	 	 	
 	 	•	 	Valuation of equity investments	
 	 	 	 	 	
Capitalization Practices/Purchase Accounting	 	•	 	Determination of beginning and ending of capitalization periods	
 	 	 	 	 	
 	 	•	 	Allocation of purchase prices to identified assets	
 	 	 	 	 	
Asset Valuation and Impairment	 	•	 	Recoverability of investment through future operations	
 	 	 	 	 	
 	 	•	 	Regulatory and political environments and requirements	
 	 	 	 	 	
 	 	•	 	Estimated useful lives of assets	
 	 	 	 	 	
 	 	•	 	Environmental obligations and operational limitations	
 	 	 	 	 	
 	 	•	 	Estimates of future cash flows	
 	 	 	 	 	
 	 	•	 	Estimates of fair value (fresh start)	
 	 	 	 	 	
 	 	•	 	Judgment about triggering events	
 	 	 	 	 	
Inventory	 	•	 	Valuation of inventory balances	
 	 	 	 	 	
Foreign Currency Translation	 	•	 	Recognition of changes in foreign currencies.	
 	 	 	 	 	
Revenue Recognition	 	•	 	Customer/counter-party dispute resolution practices	
 	 	 	 	 	
 	 	•	 	Market maturity and economic conditions	
 	 	 	 	 	
 	 	•	 	Contract interpretation	
 	 	 	 	 	
Uncollectible Receivables	 	•	 	Economic conditions affecting customers, counter parties, suppliers and market prices	
 	 	 	 	 	
 	 	•	 	Regulatory environment and impact on customer financial condition	
 	 	 	 	 	
 	 	•	 	Outcome of litigation and bankruptcy proceedings	
 	 	 	 	 	
Derivative Financial Instruments	 	•	 	Market conditions in the energy industry, especially the effects of price volatility on contractual commitments	
 	 	 	 	 	
 	 	•	 	Assumptions used in valuation models	
 	 	 	 	 	
 	 	•	 	Counter party credit risk	
 	 	 	 	 	
 	 	•	 	Market conditions in foreign countries	
 	 	 	 	 	
 	 	•	 	Regulatory and political environments and requirements	
 	 	 	 	 	
Litigation Claims and Assessments	 	•	 	Impacts of court decisions	
 	 	 	 	 	
 	 	•	 	Estimates of ultimate liabilities arising from legal claims	
 	 	 	 	 	
Income Taxes and Valuation Allowance for Deferred Tax Assets	 	•	 	Ability of tax authority decisions to withstand legal challenges or appeals	
 	 	 	 	 	
 	 	•	 	Anticipated future decisions of tax authorities	
 	 	 	 	 	
 	 	•	 	Application of tax statutes and regulations to transactions.	
 	 	 	 	 	
 	 	•	 	Ability to utilize tax benefits through carrybacks to prior periods and carryforwards to future periods.	
 	 	 	 	 	
Discontinued Operations	 	•	 	Consistent application	
 	 	 	 	 	
 	 	•	 	Determination of fair value (recoverability)	
 	 	 	 	 	
 	 	•	 	Recognition of expected gain or loss prior to disposition	
 	 	 	 	 	
Pension	 	•	 	Accuracy of management assumptions	
 	 	 	 	 	
 	 	•	 	Accuracy of actuarial consultant assumptions	
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Accounting Policy

	 	Judgments/ Uncertainties Affecting Application

	
Stock-Based Compensation	 	•	 	Accuracy of management assumptions used to determine the fair value of the stock options	
     Of all of the accounting policies identified in the above table, we believe that the following policies and the application thereof to be those having the most direct impact on our financial position and results of operations.

Fresh Start Reporting

     In connection with the emergence from bankruptcy, we adopted Fresh Start in accordance with the requirements of SOP 90-7. The application of SOP 90-7 resulted in the creation of a new reporting entity. Under Fresh Start, the reorganization value of our company was allocated among our assets and liabilities on a basis substantially consistent with purchase accounting in accordance with SFAS No. 141  “Business Combinations.”

     The bankruptcy court in its confirmation order approved our Plan of reorganization on November 24, 2003. Under the requirements of SOP 90-7, the Fresh Start date is determined to be the confirmation date unless significant uncertainties exist regarding the effectiveness of the bankruptcy order. Our Plan of reorganization required completion of the Xcel Energy settlement agreement prior to emergence from bankruptcy. We believe this settlement agreement was a significant contingency and thus delayed the Fresh Start date until the Xcel Energy settlement agreement was finalized on December 5, 2003.

     Under the requirements of Fresh Start, we have adjusted our assets and liabilities, other than deferred income taxes, to their estimated fair values as of December 5, 2003. As a result of marking our assets and liabilities to their estimated fair values, we determined that there was no excess reorganization value to recognize as an intangible asset. Deferred taxes were determined in accordance with SFAS No. 109,  “Accounting for Income Taxes.”  The net effect of all Fresh Start adjustments resulted in a gain of $3.9 billion, which is reflected in the Predecessor Company’s results for the period January 1, 2003 through December 5, 2003. The application of the Fresh Start provisions of SOP 90-7 created a new reporting entity having no retained earnings or accumulated deficit.

     As part of the bankruptcy process we engaged an independent financial advisor to assist in the determination of the fair value of our reorganized enterprise value. The fair value calculation was based on management’s forecast of our core assets. Management’s forecast relied on forward market prices obtained from a third party consulting firm. A discounted cash flow calculation was used to develop the enterprise value of Reorganized NRG, determined in part by calculating the weighted average cost of capital of the Reorganized NRG. The Discounted Cash Flow, or “DCF”, valuation methodology equates the value of an asset or business to the present value of expected future economic benefits to be generated by that asset or business. The DCF methodology is a “forward looking” approach that discounts all expected future economic benefits by a theoretical or observed discount rate determined by calculating the weighted average cost of capital, or “WACC”, of Reorganized NRG. The enterprise calculation was based on management’s forecast of our core assets. Management’s forecast relied on forward market prices obtained from a third party consulting firm. For purposes of our Disclosure statement, the independent financial advisor estimated our reorganization enterprise value of our ongoing projects to range from $5.5 billion to $5.7 billion, less project level debt, and net of cash. Certain other adjustments were made to reflect the values of assets held for sale, excess cash and net of the Xcel Settlement and collateral requirements. These adjustments resulted in a reorganized NRG value, net of project debt, of between $3.1 billion and $3.5 billion. Additional adjustments were made to reflect cash payments expected as part of the implementation of the Plan of Reorganization, resulting in a final range of equity values of between $2.2 billion and $2.6 billion.

     In constructing our Fresh Start balance sheet upon our emergence from bankruptcy we used a reorganization equity value of approximately $2.4 billion, as we believe this value to be the best indication of the value of the ownership distributed to the new equity owners. Our reorganization value of approximately $9.1 billion was determined by adding our reorganized equity value of $2.4 billion, $3.7 billion of interest bearing debt and our other liabilities of $3.0 billion. The reorganization value represents the fair value of an entity before liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after restructuring. This value is consistent with the voting creditors and Court’s approval of the Plan of Reorganization.

     A separate plan of reorganization was filed for our Northeast Generating and South Central Generating entities that was confirmed by the bankruptcy court on November 25, 2003, and became effective on December 23, 2003, when the final conditions of the plan were completed. In connection with Fresh Start on December 5, 2003, we have accounted for these entities as if they had emerged from bankruptcy at the same time that we emerged, as we believe that we continued to maintain control over the Northeast Generating and South Central Generating facilities throughout the bankruptcy process.

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     Due to the adoption of Fresh Start upon our emergence from bankruptcy, the Reorganized NRG’s post-fresh start balance sheet, statement of operations and statement of cash flows have not been prepared on a consistent basis with the Predecessor Company’s financial statements and are therefore not comparable in certain respects to the financial statements prior to the application of Fresh Start.

     Capitalization Practices and Purchase Accounting

     Predecessor Company

     For those assets that were being constructed by us, the carrying value reflects the application of our property, plant and equipment policies which incorporate estimates, assumptions and judgments by management relative to the capitalized costs and useful lives of our generating facilities. Interest incurred on funds borrowed to finance projects expected to require more than three months to complete is capitalized. Capitalization of interest is discontinued when the asset under construction is ready for our intended use or when construction is terminated. An insignificant amount of interest was capitalized during 2003. Development costs and capitalized project costs include third party professional services, permits and other costs that are incurred incidental to a particular project. Such costs are expensed as incurred until an acquisition agreement or letter of intent is signed, and our board of directors has approved the project. Additional costs incurred after this point are capitalized.

     Reorganized NRG

     In connection with the emergence from bankruptcy, we adopted Fresh Start in accordance with the requirements of SOP 90-7. The application of SOP 90-7 resulted in the creation of a new reporting entity. Under Fresh Start, the reorganization value of our company was allocated to our assets and liabilities on a basis substantially consistent with purchase accounting in accordance with SFAS No. 141. We engaged a valuation specialist to help us determine the fair value of our fixed assets. The valuations were based on forecast power prices and operating costs determined by us. The valuation specialist also determined the estimated remaining useful lives of our fixed assets. The capitalization policy will be consistent with the predecessor company policy.

     Impairment of Long Lived Assets

     We evaluate property, plant and equipment and intangible assets for impairment whenever indicators of impairment exist. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the assets to the future net cash flows expected to be generated by the asset, through considering project specific assumptions for long-term power pool prices, escalated future project operating costs and expected plant operations. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets by factoring in the probability weighting of different courses of action available to us. Generally, fair value will be determined using valuation techniques such as the present value of expected future cash flows. Assets to be disposed of are reported at the lower of the carrying amount or fair value less the cost to sell. For the period January 1, 2003 through December 5, 2003, net income from continuing operations was reduced by $228.9 million due to asset impairments. Asset impairment evaluations are by nature highly subjective.

     Revenue Recognition and Uncollectible Receivables

     We are primarily an electric generation company, operating a portfolio of majority-owned electric generating plants and certain plants in which our ownership is 50% or less which are accounted for under the equity method of accounting. We also produce thermal energy for sale to customers. Both physical and financial transactions are entered into to optimize the financial performance of our generating facilities. Electric energy revenue is recognized upon transmission to the customer. In certain markets, which are operated/controlled by an independent system operator and in which we have entered into a netting agreement with the ISO, which results in our receiving a netted invoice, we have recorded purchased energy as an offset against revenues received upon the sale of such energy. Capacity and ancillary revenue is recognized when contractually earned. Revenues from operations and maintenance services are recognized when the services are performed. We continually assess the collectibility of our receivables, and in the event we believe a receivable to be uncollectible, an allowance for doubtful accounts is recorded or, in the event of a contractual dispute, the receivable and corresponding revenue may be considered unlikely of recovery and not recorded in the financial statements until management is satisfied that it will be collected.

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     Derivative Financial Instruments

     In January 2001, we adopted FAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” or “SFAS No. 133”, as amended by SFAS No. 137, SFAS No. 138 and SFAS No. 149. SFAS No. 133 requires us to record all derivatives on the balance sheet at fair value. In some cases hedge accounting may apply. The criteria used to determine if hedge accounting treatment is appropriate are a) the designation of the hedge to an underlying exposure, b) whether or not the overall risk is being reduced and c) if there is correlation between the value of the derivative instrument and the underlying obligation. Formal documentation of the hedging relationship, the nature of the underlying risk, the risk management objective, and the means by which effectiveness will be assessed is created at the inception of the hedge. Changes in the fair value of non-hedge derivatives are immediately recognized in earnings. Changes in the fair value of derivatives accounted for as hedges are either recognized in earnings as an offset to the changes in the fair value of the related hedged assets, liabilities and firm commitments or for forecasted transactions, deferred and recorded as a component of accumulated other comprehensive income or “OCI”, until the hedged transactions occur and are recognized in earnings. We primarily account for derivatives under SFAS No. 133 such as long-term power sales contracts, long-term gas purchase contracts and other energy related commodities and financial instruments used to mitigate variability in earnings due to fluctuations in spot market prices, hedge fuel requirements at generation facilities and to protect investments in fuel inventories. SFAS No. 133 also applies to interest rate swaps and foreign currency exchange rate contracts. The application of SFAS No. 133 results in increased volatility in earnings due to the recognition of unrealized gains and losses. In determining the fair value of these derivative/financial instruments we use estimates, various assumptions, judgment of management and when considered appropriate third party experts in determining the fair value of these derivatives.

     Discontinued Operations

     We classify our results of operations that either have been disposed of or are classified as held for sale as discontinued operations if both of the following conditions are met: (a) the operations and cash flows have been (or will be) eliminated from our ongoing operations as a result of the disposal transaction and (b) we will not have any significant continuing involvement in the operations of the component after the disposal transaction. Prior periods are restated to report the operations as discontinued.

     Pensions

     The determination of our obligation and expenses for pension benefits is dependent on the selection of certain assumptions. These assumptions determined by management include the discount rate, the expected rate of return on plan assets and the rate of future compensation increases. Our actuarial consultants use assumptions for such items as retirement age. The assumptions used may differ materially from actual results, which may result in a significant impact to the amount of pension obligation or expense recorded by us.

     Stock-Based Compensation

     Effective January 1, 2003, we adopted the fair value recognition provisions of SFAS Statement No. 123, “Accounting for Stock-Based Compensation,”  or “SFAS No. 123.” In accordance with SFAS Statement No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure,”  or “SFAS No. 148”, we adopted SFAS No. 123 under the prospective transition method which requires the application of the recognition provisions to all employee awards granted, modified, or settled after the beginning of the fiscal year in which the recognition provisions are first applied.

     Recent Accounting Developments

     As part of the provisions of SOP 90-7, we are required to adopt, for the current reporting period, all accounting guidance that is effective within a twelve-month period. As a result, we have adopted all provisions of FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities.”

PART IV

Item 15 — Exhibits, Financial Statement Schedules and Reports on Form 8-K

(a)(1) Financial Statements

     The following consolidated financial statements of NRG Energy and related notes thereto, together with the reports thereon of PricewaterhouseCoopers LLP are included herein:

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     Consolidated Statements of Operations — Years ended December 31, 2001 and 2002 and for
       the period January 1, 2003 to December 5, 2003 (Predecessor Company) and the period
       December 6, 2003 to December 31, 2003 (Reorganized NRG)

     Consolidated Balance Sheets — December 31, 2002 (Predecessor Company), December 6,
       2003 and December 31, 2003 (Reorganized NRG)

     Consolidated Statements of Cash Flows — Years ended December 31, 2001 and 2002 and for
       the period January 1, 2003 to December 5, 2003 (Predecessor Company) and the period
       December 6, 2003 to December 31, 2003 (Reorganized NRG)

     Consolidated Statements of Stockholder’s (Deficit)/Equity — Years ended December 31, 2001
       and 2002 and for the period January 1, 2003 to December 5, 2003 (Predecessor Company)
       and the period December 6, 2003 to December 31, 2003 (Reorganized NRG)

     Notes to Consolidated Financial Statements

(a)(2) Financial Statement Schedule

     The following Consolidated Financial Statement Schedule of NRG Energy is filed as part of Item 15(d) of this report and should be read in conjunction with the Consolidated Financial Statements.

&nbsp;    Report of Independent Registered Public Accounting Firm on Financial Statement Schedule.

     Schedule II — Valuation and Qualifying Accounts

     All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are inapplicable, and therefore, have been omitted.

(a)(3) Exhibits: See Exhibit Index submitted as a separate section of this report.

(b) Reports on Form 8-K. We filed reports on Form 8-K on the following dates over the last fiscal year:

     February 21, 2003, March 6, 2003, May 16, 2003, August 27, 2003, October 22, 2003, November 7, 2003, November 19, 2003, December 9, 2003, December 19, 2003, December 24, 2003.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder
of NRG Energy, Inc.:

     In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, cash flows and stockholders’ equity (deficit) present fairly, in all material respects, the financial position of NRG Energy, Inc. and its subsidiaries (Predecessor Company) at December 31, 2002 and the results of their operations and their cash flows for the period from January 1, 2003 to December 5, 2003, and for each of the two years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). These standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

     As discussed in Note 1 to the consolidated financial statements, the Company filed a petition on May 14, 2003 with the United States Bankruptcy Court for the Southern District of New York for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. NRG Energy, Inc.’s Plan of Reorganization was substantially consummated on December 5, 2003 and Reorganized NRG emerged from bankruptcy. In connection with its emergence from bankruptcy, the Company adopted fresh start accounting.

     As discussed in Note 2 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets”, as of January 1, 2002. As discussed in Notes 2 and 8 to the consolidated financial statements, the Company adopted Statements of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” on January 1, 2002.

     As discussed in Note 6 to the consolidated financial statements, during the first quarter of 2004, PERC and Cobee met the criteria for discontinued operations, and during the second quarter of 2004, LSP Energy and Hsin Yu met the criteria for discontinued operations. Accordingly, all periods presented have been restated to present PERC, Cobee, LSP Energy and Hsin Yu as discontinued operations.

     As discussed in Note 20 to the consolidated financial statements, the Company revised its segment reporting in 2004 to reflect the realignment of their management team. As a result of these changes, prior period segment disclosures have been recast in a consistent manner.

 	/s/ PRICEWATERHOUSECOOPERS LLP  	 	
 	PricewaterhouseCoopers LLP 	 	

Minneapolis, Minnesota
March 10, 2004, except as to Notes 6, 20, 30, and 31, which are as of October 29, 2004

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders
of NRG Energy, Inc.:

     In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, cash flows and stockholders’ equity present fairly, in all material respects, the financial position of NRG Energy, Inc. and its subsidiaries (Reorganized NRG) at December 6, 2003 and December 31, 2003 and the results of their operations and their cash flows for the period from December 6, 2003 to December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). These standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

     As discussed in Note 1 to the consolidated financial statements, the United States Bankruptcy Court for the Southern District of New York confirmed the NRG Energy, Inc. Plan of Reorganization on November 24, 2003. Confirmation of the plan resulted in the discharge of all claims against the Company that arose before May 14, 2003 and substantially alters rights and interests of equity security holders as provided for in the plan. The NRG Energy, Inc. Plan of Reorganization was substantially consummated on December 5, 2003, and NRG Energy, Inc. emerged from bankruptcy. In connection with its emergence from bankruptcy, NRG Energy, Inc. adopted fresh start accounting as of December 5, 2003.

     As discussed in Note 6 to the consolidated financial statements, during the first quarter of 2004, PERC and Cobee met the criteria for discontinued operations, and during the second quarter of 2004, LSP Energy and Hsin Yu met the criteria for discontinued operations. Accordingly, all periods presented have been restated to present PERC, Cobee, LSP Energy and Hsin Yu as discontinued operations.

     As discussed in Note 20 to the consolidated financial statements, the Company revised its segment reporting in 2004 to reflect the realignment of their management team. As a result of these changes, prior period segment disclosures have been recast in a consistent manner.

 	/s/ PRICEWATERHOUSECOOPERS LLP  	 	
 	           PricewaterhouseCoopers LLP 	 	

Minneapolis, Minnesota
March 10, 2004, except as to Notes 6, 20, 30, and 31, which are as of October 29, 2004

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NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor Company

	 	Reorganized NRG

	
 	 	Year Ended December 31,	 	January 1, 2003	 	December 6, 2003	

	 	Through	 	Through	
 	 	2001

	 	2002

	 	December 5, 2003

	 	December 31, 2003

	
 	 	(In thousands, except per share amounts)	
Operating Revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues from majority-owned operations	 	$	2,085,597	 	 	$	1,938,549	 	 	$	1,798,614	 	 	$	138,507	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cost of majority-owned operations	 	 	1,377,093	 	 	 	1,334,263	 	 	 	1,357,531	 	 	 	95,602	 	
Depreciation and amortization	 	 	142,083	 	 	 	208,149	 	 	 	219,201	 	 	 	11,808	 	
General, administrative and development	 	 	187,302	 	 	 	218,914	 	 	 	170,392	 	 	 	12,541	 	
Other charges (credits)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Legal settlement	 	 	—	 	 	 	—	 	 	 	462,631	 	 	 	—	 	
Fresh start reporting adjustments	 	 	—	 	 	 	—	 	 	 	(4,118,636	)	 	 	—	 	
Reorganization items	 	 	—	 	 	 	—	 	 	 	197,825	 	 	 	2,461	 	
Restructuring and impairment charges	 	 	—	 	 	 	2,563,060	 	 	 	237,575	 	 	 	—	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total operating costs and expenses	 	 	1,706,478	 	 	 	4,324,386	 	 	 	(1,473,481	)	 	 	122,412	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Operating Income/(Loss)	 	 	379,119	 	 	 	(2,385,837	)	 	 	3,272,095	 	 	 	16,095	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Other Income/(Expense)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Minority interest in earnings of consolidated subsidiaries	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(134	)	
Equity in earnings of unconsolidated affiliates	 	 	210,032	 	 	 	68,996	 	 	 	170,901	 	 	 	13,521	 	
Write downs and losses on sales of equity method investments	 	 	—	 	 	 	(200,472	)	 	 	(147,124	)	 	 	—	 	
Other income, net	 	 	22,983	 	 	 	11,430	 	 	 	19,208	 	 	 	96	 	
Interest expense	 	 	(364,111	)	 	 	(452,184	)	 	 	(329,889	)	 	 	(18,902	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total other expense	 	 	(131,096	)	 	 	(572,230	)	 	 	(286,904	)	 	 	(5,419	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Income/(Loss) From Continuing Operations Before Income Taxes	 	 	248,023	 	 	 	(2,958,067	)	 	 	2,985,191	 	 	 	10,676	 	
Income Tax Expense/(Benefit)	 	 	37,974	 	 	 	(166,867	)	 	 	37,929	 	 	 	(661	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Income/(Loss) From Continuing Operations	 	 	210,049	 	 	 	(2,791,200	)	 	 	2,947,262	 	 	 	11,337	 	
Income/(Loss) on Discontinued Operations, net of Income Taxes	 	 	55,155	 	 	 	(673,082	)	 	 	(180,817	)	 	 	(312	) 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Net Income/(Loss)	 	$	265,204	 	 	$	(3,464,282	)	 	$	2,766,445	 	 	$	11,025	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Weighted Average Number of Common Shares Outstanding — Basic	 	 	 	 	 	 	 	 	 	 	 	 	 	 	100,000	 	
Income From Continuing Operations per Weighted Average Common Share — Basic	 	 	 	 	 	 	 	 	 	 	 	 	 	$	0.11	 	
Loss From Discontinued Operations per Weighted Average Common Share — Basic	 	 	 	 	 	 	 	 	 	 	 	 	 	 	—	 	
Net Income per Weighted Average Common Share — Basic	 	 	 	 	 	 	 	 	 	 	 	 	 	$	0.11	 	
Weighted Average Number of Common Shares Outstanding — Diluted	 	 	 	 	 	 	 	 	 	 	 	 	 	 	100,060	 	
Income From Continuing Operations per Weighted Average Common Share — Diluted	 	 	 	 	 	 	 	 	 	 	 	 	 	$	0.11	 	
Loss From Discontinued Operations per Weighted Average Common Share — Diluted	 	 	 	 	 	 	 	 	 	 	 	 	 	 	—	 	
Net Income per Weighted Average Common Shares — Diluted	 	 	 	 	 	 	 	 	 	 	 	 	 	$	0.11	 	
See notes to consolidated financial statements.

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NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor Company

	 	Reorganized NRG

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2002

	 	2003

	 	2003

	
 	 	(In thousands)	
ASSETS	 	 	 	 	 	 	 	 	 	 	 	 	
Current Assets	 	 	 	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	360,860	 	 	$	395,982	 	 	$	551,223	 	
Restricted cash	 	 	211,966	 	 	 	493,047	 	 	 	116,067	 	
Accounts receivable-trade, less allowance for doubtful accounts of $18,163, $0 and $0	 	 	257,620	 	 	 	213,479	 	 	 	201,921	 	
Xcel Energy settlement receivable	 	 	—	 	 	 	640,000	 	 	 	640,000	 	
Current portion of notes receivable — affiliates	 	 	2,442	 	 	 	—	 	 	 	200	 	
Current portion of notes receivable	 	 	52,269	 	 	 	66,628	 	 	 	65,141	 	
Income tax receivable	 	 	8,388	 	 	 	—	 	 	 	—	 	
Inventory	 	 	254,012	 	 	 	196,236	 	 	 	194,926	 	
Derivative instruments valuation	 	 	28,791	 	 	 	161	 	 	 	772	 	
Prepayments and other current assets	 	 	133,717	 	 	 	210,597	 	 	 	222,178	 	
Current deferred income tax	 	 	—	 	 	 	—	 	 	 	1,850	 	
Current assets — discontinued operations	 	 	238,432	 	 	 	126,520	 	 	 	119,561	 	

 	 	 	 	

 	 	 	 	

 	 	
Total current assets	 	 	1,548,497	 	 	 	2,342,650	 	 	 	2,113,839	 	

 	 	 	 	

 	 	 	 	

 	 	
Property, Plant and Equipment	 	 	 	 	 	 	 	 	 	 	 	 	
In service	 	 	5,693,984	 	 	 	3,876,795	 	 	 	3,885,465	 	
Under construction	 	 	611,177	 	 	 	132,003	 	 	 	139,171	 	

 	 	 	 	

 	 	 	 	

 	 	
Total property, plant and equipment	 	 	6,305,161	 	 	 	4,008,798	 	 	 	4,024,636	 	
Less accumulated depreciation	 	 	(501,961	)	 	 	—	 	 	 	(11,800	)	

 	 	 	 	

 	 	 	 	

 	 	
Net property, plant and equipment	 	 	5,803,200	 	 	 	4,008,798	 	 	 	4,012,836	 	

 	 	 	 	

 	 	 	 	

 	 	
Other Assets	 	 	 	 	 	 	 	 	 	 	 	 	
Equity investments in affiliates	 	 	884,263	 	 	 	733,862	 	 	 	737,998	 	
Notes receivable, less current portion — affiliates	 	 	151,552	 	 	 	125,651	 	 	 	130,152	 	
Notes receivable, less current portion	 	 	784,432	 	 	 	674,931	 	 	 	691,444	 	
Decommissioning fund investments	 	 	4,617	 	 	 	4,787	 	 	 	4,809	 	
Intangible assets, net of accumulated amortization of $21,618, $0 and $5,212	 	 	75,131	 	 	 	484,668	 	 	 	432,361	 	
Debt issuance costs, net of accumulated amortization of $42,411, $0 and $454	 	 	129,160	 	 	 	—	 	 	 	74,337	 	
Derivative instruments valuation	 	 	90,766	 	 	 	66,442	 	 	 	59,907	 	
Funded letter of credit	 	 	—	 	 	 	—	 	 	 	250,000	 	
Other assets	 	 	17,499	 	 	 	112,890	 	 	 	118,336	 	
Non-current assets — discontinued operations	 	 	1,407,734	 	 	 	612,650	 	 	 	618,968	 	

 	 	 	 	

 	 	 	 	

 	 	
Total other assets	 	 	3,545,154	 	 	 	2,815,881	 	 	 	3,118,312	 	

 	 	 	 	

 	 	 	 	

 	 	
Total Assets	 	$	10,896,851	 	 	$	9,167,329	 	 	$	9,244,987	 	

 	 	 	 	

 	 	 	 	

 	 	
See notes to consolidated financial statements.

38

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NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS — (Continued)
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor Company

	 	Reorganized NRG

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2002

	 	2003

	 	2003

	
 	 	(In thousands)	
LIABILITIES AND STOCKHOLDERS’ EQUITY/(DEFICIT)	 	 	 	 	 	 	 	 	 	 	 	 	
Current Liabilities	 	 	 	 	 	 	 	 	 	 	 	 	
Current portion of long-term debt	 	$	7,001,134	 	 	$	2,496,754	 	 	$	801,229	 	
Revolving line of credit	 	 	1,000,000	 	 	 	—	 	 	 	—	 	
Short-term debt	 	 	30,064	 	 	 	18,645	 	 	 	19,019	 	
Accounts payable — trade	 	 	540,171	 	 	 	202,471	 	 	 	158,683	 	
Accounts payable — affiliates	 	 	57,961	 	 	 	16,988	 	 	 	7,053	 	
Accrued income tax	 	 	—	 	 	 	16,431	 	 	 	16,095	 	
Accrued property, sales and other taxes	 	 	24,271	 	 	 	27,814	 	 	 	22,322	 	
Accrued salaries, benefits and related costs	 	 	16,844	 	 	 	16,719	 	 	 	19,331	 	
Accrued interest	 	 	277,116	 	 	 	75,773	 	 	 	8,982	 	
Derivative instruments valuation	 	 	13,439	 	 	 	95	 	 	 	429	 	
Creditor pool obligation	 	 	—	 	 	 	1,040,000	 	 	 	540,000	 	
Other bankruptcy settlement	 	 	—	 	 	 	220,000	 	 	 	220,000	 	
Other current liabilities	 	 	105,341	 	 	 	136,775	 	 	 	102,861	 	
Current liabilities — discontinued operations	 	 	763,070	 	 	 	108,975	 	 	 	110,177	 	

 	 	 	 	

 	 	 	 	

 	 	
Total current liabilities	 	 	9,829,411	 	 	 	4,377,440	 	 	 	2,026,181	 	
Other Liabilities	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term debt	 	 	781,514	 	 	 	879,686	 	 	 	3,327,782	 	
Deferred income taxes	 	 	74,886	 	 	 	144,688	 	 	 	149,493	 	
Postretirement and other benefit obligations	 	 	67,495	 	 	 	104,712	 	 	 	105,946	 	
Derivative instruments valuation	 	 	91,039	 	 	 	155,709	 	 	 	153,503	 	
Other long-term obligations	 	 	145,594	 	 	 	536,682	 	 	 	480,938	 	
Non-current liabilities — discontinued operations	 	 	602,600	 	 	 	559,560	 	 	 	558,884	 	

 	 	 	 	

 	 	 	 	

 	 	
Total non-current liabilities	 	 	1,763,128	 	 	 	2,381,037	 	 	 	4,776,546	 	

 	 	 	 	

 	 	 	 	

 	 	
Total liabilities	 	 	11,592,539	 	 	 	6,758,477	 	 	 	6,802,727	 	

 	 	 	 	

 	 	 	 	

 	 	
Minority interest	 	 	511	 	 	 	4,852	 	 	 	5,004	 	
Commitments and Contingencies	 	 	 	 	 	 	 	 	 	 	 	 	
Stockholders’ Equity/(Deficit)	 	 	 	 	 	 	 	 	 	 	 	 	
Class A — Common stock; $.01 par value; 100 shares authorized in 2002; 3 shares issued and outstanding at December 31, 2002	 	 	—	 	 	 	—	 	 	 	—	 	
Common stock; $.01 par value; 100 shares authorized in 2002; 1 share issued and outstanding at December 31, 2002	 	 	—	 	 	 	—	 	 	 	—	 	
Common stock; $.01 par value; 500,000,000 shares authorized in 2003; 100,000,000 shares issued and outstanding at December 6, 2003 and December 31, 2003	 	 	—	 	 	 	1,000	 	 	 	1,000	 	
Additional paid-in capital	 	 	2,227,692	 	 	 	2,403,000	 	 	 	2,403,429	 	
Retained earnings/(deficit)	 	 	(2,828,933	)	 	 	—	 	 	 	11,025	 	
Accumulated other comprehensive income (loss)	 	 	(94,958	)	 	 	—	 	 	 	21,802	 	

 	 	 	 	

 	 	 	 	

 	 	
Total stockholders’ equity/(deficit)	 	 	(696,199	)	 	 	2,404,000	 	 	 	2,437,256	 	

 	 	 	 	

 	 	 	 	

 	 	
Total Liabilities and Stockholders’ Equity/(Deficit)	 	$	10,896,851	 	 	$	9,167,329	 	 	$	9,244,987	 	

 	 	 	 	

 	 	 	 	

 	 	
See notes to consolidated financial statements.

39

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NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor Company

	 	Reorganized NRG

	
 	 	Year Ended December 31	 	January 1, 2003	 	December 6, 2003	

	 	Through	 	Through	
 	 	2001

	 	2002

	 	December 5, 2003

	 	December 31, 2003

	
 	 	(In thousands)	
Cash Flows from Operating Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income/(loss)	 	$	265,204	 	 	$	(3,464,282	)	 	$	2,766,445	 	 	$	11,025	 	
Adjustments to reconcile net income/(loss) to net cash provided by operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Distributions in excess of (less than) equity earnings of unconsolidated affiliates	 	 	(119,002	)	 	 	(22,252	)	 	 	(41,472	)	 	 	2,229	 	
Depreciation and amortization	 	 	212,493	 	 	 	286,623	 	 	 	256,700	 	 	 	13,041	 	
Amortization of deferred financing costs	 	 	10,668	 	 	 	28,367	 	 	 	17,640	 	 	 	517	 	
Amortization of debt discount/(premium)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1,725	 	
Write downs and losses on sales of equity method investments	 	 	—	 	 	 	196,192	 	 	 	146,938	 	 	 	—	 	
Deferred income taxes and investment tax credits	 	 	45,556	 	 	 	(230,134	)	 	 	(1,893	)	 	 	(3,262	)	
Unrealized (gains)/losses on derivatives	 	 	(13,257	)	 	 	(2,743	)	 	 	(34,616	)	 	 	3,774	 	
Minority interest	 	 	6,564	 	 	 	(19,325	)	 	 	2,177	 	 	 	204	 	
Amortization of out of market power contracts	 	 	(54,963	)	 	 	(89,415	)	 	 	—	 	 	 	(13,431	)	
Restructuring & impairment charges	 	 	—	 	 	 	3,144,509	 	 	 	408,377	 	 	 	—	 	
Fresh start reporting adjustments	 	 	—	 	 	 	—	 	 	 	(3,895,541	)	 	 	—	 	
Gain on sale of discontinued operations	 	 	—	 	 	 	(2,814	)	 	 	(186,331	)	 	 	—	 	
Cash provided by (used in) changes in certain working capital items, net of effects from acquisitions and dispositions	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Accounts receivable, net	 	 	89,523	 	 	 	(15,487	)	 	 	28,261	 	 	 	18,030	 	
Accounts receivable-affiliates	 	 	—	 	 	 	2,271	 	 	 	—	 	 	 	—	 	
Inventory	 	 	(111,131	)	 	 	42,596	 	 	 	14,128	 	 	 	11,054	 	
Prepayments and other current assets	 	 	(36,530	)	 	 	(58,368	)	 	 	(36,812	)	 	 	(9,504	)	
Accounts payable	 	 	(4,512	)	 	 	278,900	 	 	 	693,663	 	 	 	(40,927	)	
Accounts payable-affiliates	 	 	4,989	 	 	 	47,049	 	 	 	(45,017	)	 	 	832	 	
Accrued income taxes	 	 	(75,132	)	 	 	44,137	 	 	 	21,244	 	 	 	(1,207	)	
Accrued property and sales taxes	 	 	4,054	 	 	 	27,481	 	 	 	(3,159	)	 	 	(4,590	)	
Accrued salaries, benefits, and related costs	 	 	15,785	 	 	 	(24,912	)	 	 	40,690	 	 	 	3,150	 	
Accrued interest	 	 	35,637	 	 	 	203,234	 	 	 	158,581	 	 	 	(64,026	)	
Other current liabilities	 	 	82,754	 	 	 	47,692	 	 	 	(22,797	)	 	 	(510,867	)	
Other assets and liabilities	 	 	(82,686	)	 	 	10,723	 	 	 	(48,697	)	 	 	(6,642	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Net Cash Provided (Used) by Operating Activities	 	 	276,014	 	 	 	430,042	 	 	 	238,509	 	 	 	(588,875	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Cash Flows from Investing Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Acquisitions, net of liabilities assumed	 	 	(2,813,117	)	 	 	—	 	 	 	—	 	 	 	—	 	
Proceeds from sale of discontinued operations	 	 	—	 	 	 	160,791	 	 	 	18,612	 	 	 	—	 	
Proceeds from sale of investments	 	 	4,063	 	 	 	68,517	 	 	 	107,174	 	 	 	—	 	
Proceeds from sale of turbines	 	 	—	 	 	 	—	 	 	 	70,717	 	 	 	—	 	
(Increase) in trust funds	 	 	—	 	 	 	—	 	 	 	(13,971	)	 	 	—	 	
Decrease/(increase) in restricted cash	 	 	(99,707	)	 	 	(197,802	)	 	 	(252,495	)	 	 	375,272	 	
Decrease/(increase) in notes receivable	 	 	45,091	 	 	 	(209,244	)	 	 	(1,653	)	 	 	1,182	 	
Capital expenditures	 	 	(1,322,130	)	 	 	(1,439,733	)	 	 	(113,502	)	 	 	(10,560	)	
Investments in projects	 	 	(149,841	)	 	 	(63,996	)	 	 	(561	)	 	 	(2,522	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Net Cash Provided (Used) by Investing Activities	 	 	(4,335,641	)	 	 	(1,681,467	)	 	 	(185,679	)	 	 	363,372	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Cash Flows from Financing Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net borrowings under line of credit agreement	 	 	202,000	 	 	 	790,000	 	 	 	—	 	 	 	—	 	
Proceeds from issuance of stock	 	 	475,464	 	 	 	4,065	 	 	 	—	 	 	 	—	 	
Proceeds from issuance of corporate units (warrants)	 	 	4,080	 	 	 	—	 	 	 	—	 	 	 	—	 	
Proceeds from issuance of short term debt	 	 	622,156	 	 	 	—	 	 	 	—	 	 	 	—	 	
40

Table of Contents
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor Company

	 	Reorganized NRG

	
 	 	Year Ended December 31

	 	January 1, 2003	 	December 6, 2003	
 	 	 	 	 	 	 	 	 	 	Through	 	Through	
 	 	2001

	 	2002

	 	December 5, 2003

	 	December 31, 2003

	
 	 	(In thousands)	
Capital contributions from parent	 	 	—	 	 	 	500,000	 	 	 	—	 	 	 	—	 	
Proceeds from issuance of long-term debt	 	 	3,268,017	 	 	 	1,086,770	 	 	 	39,988	 	 	 	2,450,000	 	
Deferred debt issuance costs	 	 	—	 	 	 	—	 	 	 	(18,540	)	 	 	(74,795	)	
Funded letter of credit	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(250,000	)	
Principal payments on long-term debt	 	 	(418,171	)	 	 	(931,505	)	 	 	(51,392	)	 	 	(1,731,932	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Net Cash Provided (Used) by Financing Activities	 	 	4,153,546	 	 	 	1,449,330	 	 	 	(29,944	)	 	 	393,273	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Effect of Exchange Rate Changes on Cash and Cash Equivalents	 	 	(3,055	)	 	 	24,950	 	 	 	(22,276	)	 	 	(13,562	)	
Change in Cash from Discontinued Operations	 	 	(40,873	)	 	 	51,267	 	 	 	34,512	 	 	 	1,033	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Net Increase in Cash and Cash Equivalents	 	 	49,991	 	 	 	274,122	 	 	 	35,122	 	 	 	155,241	 	
Cash and Cash Equivalents at Beginning of Period	 	 	36,747	 	 	 	86,738	 	 	 	360,860	 	 	 	395,982	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Cash and Cash Equivalents at End of Period	 	$	86,738	 	 	$	360,860	 	 	$	395,982	 	 	$	551,223	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
See notes to consolidated financial statements.

41

Table of Contents

NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY/(DEFICIT)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Accumulated	 	Total	
 	 	Class A Common	 	Common	 	Additional	 	Retained	 	Other	 	Stockholders’	

	 	

	 	Paid-in	 	Earnings/	 	Comprehensive	 	Equity/	
 	 	Stock

	 	Shares

	 	Stock

	 	Shares

	 	Capital

	 	(Deficit)

	 	Income/(Loss)

	 	(Deficit)

	
 	 	(In thousands)	
Balances at December 31, 2000 (Predecessor Company)	 	$	1,476	 	 	 	147,605	 	 	$	324	 	 	 	32,396	 	 	$	1,233,833	 	 	$	370,145	 	 	$	(143,690	)	 	$	1,462,088	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Net income	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	265,204	 	 	 	 	 	 	 	265,204	 	
Foreign currency translation adjustments and other	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(41,600	)	 	 	(41,600	)	
Deferred unrealized gains, net on derivatives	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	71,101	 	 	 	71,101	 	

 	 	
Comprehensive income for 2001	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	294,705	 	
Capital stock activity:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Issuance of corporate units/ warrant	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	4,080	 	 	 	 	 	 	 	 	 	 	 	4,080	 	
Tax benefits of stock option exercise	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	792	 	 	 	 	 	 	 	 	 	 	 	792	 	
Issuance of common stock, net of issuance costs of $23.5 million	 	 	 	 	 	 	 	 	 	 	185	 	 	 	18,543	 	 	 	475,279	 	 	 	 	 	 	 	 	 	 	 	475,464	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Balances at December 31, 2001 (Predecessor Company)	 	$	1,476	 	 	 	147,605	 	 	$	509	 	 	 	50,939	 	 	$	1,713,984	 	 	$	635,349	 	 	$	(114,189	)	 	$	2,237,129	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Net loss	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(3,464,282	)	 	 	 	 	 	 	(3,464,282	)	
Foreign currency translation adjustments and other	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	64,054	 	 	 	64,054	 	
Deferred unrealized loss, net on derivatives	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(44,823	)	 	 	(44,823	)	

 	 	
Comprehensive loss for 2002	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(3,445,051	)	
Contribution from parent	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	502,874	 	 	 	 	 	 	 	 	 	 	 	502,874	 	
Issuance of common stock	 	 	 	 	 	 	 	 	 	 	6	 	 	 	591	 	 	 	8,843	 	 	 	 	 	 	 	 	 	 	 	8,849	 	
Impact of exchange offer	 	 	(1,476	)	 	 	(147,605	)	 	 	(515	)	 	 	(51,530	)	 	 	1,991	 	 	 	 	 	 	 	 	 	 	 	—	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Balances at December 31, 2002 (Predecessor Company)	 	$	—	 	 	 	—	 	 	$	—	 	 	 	—	 	 	$	2,227,692	 	 	$	(2,828,933	)	 	$	(94,958	)	 	$	(696,199	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Net income	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	2,766,445	 	 	 	 	 	 	 	2,766,445	 	
Foreign currency translation adjustments and other	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	127,754	 	 	 	127,754	 	
Deferred unrealized loss, net on derivatives	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(31,363	)	 	 	(31,363	)	

 	 	
Comprehensive income for the period from January 1, 2003 through December 5, 2003	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	2,862,836	 	
Effects of reorganization	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(2,227,692	)	 	 	62,488	 	 	 	(1,433	)	 	 	(2,166,637	)	
Issuance of common stock	 	 	 	 	 	 	 	 	 	 	1,000	 	 	 	100,000	 	 	 	2,403,000	 	 	 	 	 	 	 	 	 	 	 	2,404,000	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Balances at December 5, 2003 (Predecessor Company)	 	$	—	 	 	 	—	 	 	$	1,000	 	 	 	100,000	 	 	$	2,403,000	 	 	$	—	 	 	$	—	 	 	$	2,404,000	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Net income	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	11,025	 	 	 	 	 	 	 	11,025	 	
Foreign currency translation adjustments and other	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	22,325	 	 	 	22,325	 	
Deferred unrealized loss, net on derivatives	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(523	)	 	 	(523	)	

 	 	
Comprehensive income for the period from December 6, 2003 through December 31, 2003	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	32,827	 	
Compensation expense related to stock option plan	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	429	 	 	 	 	 	 	 	 	 	 	 	429	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Balances at December 31, 2003 (Reorganized NRG)	 	$	—	 	 	 	—	 	 	$	1,000	 	 	 	100,000	 	 	$	2,403,429	 	 	$	11,025	 	 	$	21,802	 	 	$	2,437,256	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
See notes to consolidated financial statements.

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NRG ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Organization

General

     We are a wholesale power generation company, primarily engaged in the ownership and operation of power generation facilities and the sale of energy, capacity and related products in the United States and internationally. We have a diverse portfolio of electric generation facilities in terms of geography, fuel type, and dispatch levels. We seek to maximize operating income through the efficient procurement and management of fuel supplies and maintenance services, and the sale of energy, capacity and ancillary services into attractive spot, intermediate and long-term markets.

     We were formed in 1992 as the non-regulated subsidiary of Northern States Power, or “NSP”, which was itself merged into New Century Energies, Inc. to form Xcel Energy, Inc., or “Xcel Energy” in 2000. While owned by NSP and later by Xcel Energy, we consistently pursued an aggressive high growth strategy focused on power plant acquisitions, high leverage and aggressive development, including site development and turbine orders. In 2002, a number of factors most notably the aggressive prices paid by us for our acquisitions of turbines, development projects and plants, combined with the overall downturn in the power generation industry, triggered a credit rating downgrade (below investment grade), which in turn, precipitated a severe liquidity situation. On May 14, 2003, we and 25 of our direct and indirect wholly owned subsidiaries commenced voluntary petitions under chapter 11 of the bankruptcy code in the United States Bankruptcy Court for the Southern District of New York. On November 24, 2003, the bankruptcy court entered an order confirming our plan of reorganization and the plan became effective on December 5, 2003.

     As part of the plan of reorganization, Xcel Energy relinquished its ownership interest and we became an independent public company upon our emergence from bankruptcy on December 5, 2003. We no longer have any material affiliation or relationship with Xcel Energy. As part of that reorganization, we eliminated approximately $5.2 billion of corporate level bank and bond debt and approximately $1.3 billion of additional claims and disputes by distributing a combination of equity and up to $1.04 billion in cash among our unsecured creditors. In addition to the debt reduction associated with the restructuring, we used a substantial portion of the proceeds of a recent note offering and borrowings under a new credit facility, the “Refinancing Transactions,” to retire approximately $1.7 billion of project-level debt on December 23, 2003. In January 2004, we used proceeds of an additional note offering to repay $503.5 million of the outstanding borrowings under our New Credit facility.

     As of December 31, 2003, we owned interests in 72 power projects in seven countries having an aggregate generation capacity of approximately 18,200 MW. Approximately 7,900 MW of our capacity consists of merchant power plants in the Northeast region of the United States. Certain of these assets are located in transmission constrained areas, including approximately 1,400 MW of “in-city” New York City generation capacity and approximately 700 MW of southwest Connecticut generation capacity. We also own approximately 2,500 MW of capacity in the South Central region of the United States, with approximately 1,700 MW of that capacity supported by long-term power purchase agreements. Our assets in the West Coast region of the United States consist of approximately 1,300 MW of capacity with the majority of such capacity owned via our 50% interest in West Coast Power, LLC, or “West Coast Power.” Our assets in the West Coast region are supported by a power purchase agreement with the California Department of Water Resources that runs through December 2004. Our principal domestic generation assets consisted of a diversified mix of natural gas-, coal- and oil-fired facilities, representing approximately 48%, 26% and 26% of our total domestic generation capacity, respectively. We also own interests in plants having a generation capacity of approximately 3,000 MW in various international markets, including Australia, Europe and Latin America. Our energy marketing subsidiary, NRG Power Marketing, Inc., or “PMI” began operations in 1998 and is focused on maximizing the value of our North American assets by providing centralized contract origination and management services, and through the efficient procurement and management of fuel and the sale of energy and related products in the spot, intermediate and long-term markets.

     We were incorporated as a Delaware corporation on May 29, 1992. Our headquarters and principal executive offices are located at 901 Marquette Avenue, Suite 2300, Minneapolis, Minnesota, 55402. Our telephone number is (612) 373-5300. Our Internet website is http://www.nrgenergy.com. Our recent annual reports, quarterly reports, current reports and other periodic filings are available free of charge through our Internet website.

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The Bankruptcy Case

     On May 14, 2003, we and 25 of our direct and indirect wholly owned subsidiaries commenced voluntary petitions under chapter 11 of the bankruptcy code in the United States Bankruptcy Court for the Southern District of New York, or “the bankruptcy court.” During the bankruptcy proceedings, we continued to conduct our business and manage our properties as debtors in possession pursuant to sections 1107(a) and 1108 of the bankruptcy code. Our subsidiaries that own our international operations, and certain other subsidiaries, were not part of these chapter 11 cases or any of the subsequent bankruptcy filings. On November 24, 2003, the bankruptcy court entered an order confirming the NRG plan of reorganization, and the plan became effective on December 5, 2003.

     Events Leading to the Commencement of the Chapter 11 Filing

     Since the 1990’s, we pursued a strategy of growth through acquisitions and later the development of new construction projects. This strategy required significant capital, much of which was satisfied primarily with third party debt. Due to a number of reasons, particularly our aggressive pricing of acquisitions and the overall downturn in the power generation industry, our financial condition deteriorated significantly starting in 2001. During 2002, our senior unsecured debt and our project-level secured debt were downgraded multiple times by rating agencies. In September 2002, we failed to make payments due under certain unsecured bond obligations, which resulted in further downgrades.

     As a result of the downgrades, the debt load incurred during the course of acquiring assets, declining power prices, increasing fuel prices, the overall downturn in the power generation industry and the overall downturn in the economy, we experienced severe financial difficulties. These difficulties caused us to, among other things, miss scheduled principal and interest payments due to our corporate lenders and bondholders, be required to prepay for fuel and other related delivery and transportation services and be required to provide performance collateral in certain instances. We also recorded asset impairment charges of approximately $3.1 billion during 2002, while we were a wholly-owned subsidiary of Xcel Energy, related to various operating projects as well as for projects that were under construction which we had stopped funding and turbines we had purchased for which we no longer had a use.

     In addition, our missed payments resulted in cross-defaults of numerous other non-recourse and limited recourse debt instruments and caused the acceleration of multiple debt instruments, rendering such debt immediately due and payable. In addition, as a result of the downgrades, we received demands under outstanding letters of credit to post collateral aggregating approximately $1.2 billion.

     In August 2002, we retained financial and legal restructuring advisors to assist our management in the preparation of a comprehensive financial and operational restructuring. In March 2003, Xcel Energy announced that its board of directors had approved a tentative settlement agreement with us, the holders of most of our long-term notes and the steering committee representing our bank lenders.

     We filed two plans of reorganization in connection with our restructuring efforts. The first, filed on May 14, 2003, and referred to as the NRG plan of reorganization, relates to us and the other NRG plan debtors. The second plan, relating to our Northeast and South Central subsidiaries, which we refer to as the Northeast/South Central plan of reorganization, was filed on September 17, 2003. On November 25, 2003, the bankruptcy court entered an order confirming the Northeast/South Central plan of reorganization and the plan became effective on December 23, 2003.

     On June 6, 2003, LSP-Nelson Energy LLC and NRG Nelson Turbines LLC filed for protection under chapter 11 of the bankruptcy code and on August 19, 2003, NRG McClain LLC filed for protection under chapter 11 of the bankruptcy code. This annual report does not address the plans of reorganization of these subsidiaries because they are not material to our operations and we expect to sell or otherwise dispose of our interest in each subsidiary subsequent to our reorganization.

     The following description of the material terms of the NRG plan of reorganization and the Northeast/ South Central plan of reorganization is subject to, and qualified in its entirety by, reference to the detailed provisions of the NRG plan of reorganization and NRG disclosure statement, and the Northeast/South Central plan of reorganization and Northeast/South Central disclosure statement, all of which are available for review upon request.

     NRG Plan of Reorganization

     The NRG plan of reorganization is the result of several months of intense negotiations among us, Xcel Energy and the two principal committees representing our creditor groups, which we refer to as the Global Steering Committee and the Noteholder Committee. A principal component of the NRG plan of reorganization is a settlement with Xcel Energy in which Xcel Energy agreed

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to make a contribution consisting of cash (and, under certain circumstances, its stock) in the aggregate amount of up to $640 million to be paid in three separate installments following the effective date of the NRG plan of reorganization. The Xcel Energy settlement agreement resolves any and all claims existing between Xcel Energy and us and/or our creditors and, in exchange for the Xcel Energy contribution, Xcel Energy is receiving a complete release of claims from us and our creditors, except for a limited number of creditors who have preserved their claims as set forth in the confirmation order entered on November 24, 2003.

     Under the terms of the Xcel Energy settlement agreement, the Xcel Energy contribution will be or has been paid as follows:
•	 	An initial installment of $238 million in cash was paid on February 20, 2004.	

•	 	A second installment of $50 million in cash was paid on February 20, 2004.	

•	 	A third installment of $352 million in cash, which Xcel Energy is required to pay on April 30, 2004.	
     On November 24, 2003, the bankruptcy court issued an order confirming the NRG plan of reorganization, and the plan became effective on December 5, 2003. To consummate the NRG plan of reorganization, we have or will, among other things:
•	 	Satisfy general unsecured claims by:	 	 	
 	
•	 	issuing new NRG Energy common stock to holders of certain classes of allowed general unsecured claims; and	 	 	
 	
•	 	making cash payments in the amount of up to $1.04 billion to holders of certain classes of allowed general unsecured claims of which $500 million was paid in December 2003, with proceeds of the Refinancing Transactions;	 	 	
 	
•	 	Satisfy certain secured claims by either:	 	 	
 	
•	 	distributing the collateral to the security holder,	 	 	
 	
•	 	selling the collateral and distributing the proceeds to the security holder or	 	 	
 	
•	 	other mutually agreeable treatment; and	 	 	
 	
•	 	Issue to Xcel Energy a $10 million non-amortizing promissory note which will:	 	 	
 	
•	 	accrue interest at a rate of 3% per annum, and	 	 	
 	
•	 	mature 2.5 years after the effective date of the NRG plan of reorganization.	 	 	
     Northeast/South Central Plan of Reorganization

     The Northeast/South Central plan of reorganization was proposed on September 17, 2003 after we secured the necessary financing commitments. On November 25, 2003, the bankruptcy court issued an order confirming the Northeast/South Central plan of reorganization and the plan became effective on December 23, 2003. In connection with the order confirming the Northeast/South Central plan of reorganization, the court entered a separate order which provides that the allowed amount of the bondholders’ claims shall equal in the aggregate the sum of (i) $1.3 billion plus (ii) any accrued and unpaid interest at the applicable contract rates through the date of payment to the indenture trustee plus (iii) the reasonable fees, costs or expenses of the collateral agent and indenture trustee (other than reasonable professional fees incurred from October 1, 2003) plus (iv) $19.6 million, ratably, for each holder of bonds based upon the current outstanding principal amount of the bonds and irrespective of (a) the date of maturity of the bonds, (b) the interest rate applicable to such bonds and (c) the issuer of the bonds. The settlement further provides that the Northeast/South Central debtors shall reimburse the informal committee of secured bondholders, the indenture trustee, the collateral agent, and two additional bondholder groups, for any reasonable professional fees, costs or expenses incurred from October 1, 2003 through January 31, 2004 up to a maximum amount of $2.5 million (including in such amount any post-October 1, 2003 fees already reimbursed), with the exception that the parties to the settlement reserved their respective rights with respect to any additional reasonable fees, costs or expenses incurred subsequent to November 25, 2003 related to matters not reasonably contemplated by the implementation of the settlement of the Northeast/South Central plan of reorganization.

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     The creditors of Northeast and South Central subsidiaries are unimpaired by the Northeast/South Central plan of reorganization. This means that holders of allowed general unsecured claims were paid in cash, in full on the effective date of the Northeast/South Central plan of reorganization. Holders of allowed secured claims will receive or have received either (i) cash equal to the unpaid portion of their allowed unsecured claim, (ii) treatment that leaves unaltered the legal, equitable and contractual rights to which such unsecured claim entitles the holder of such claim, (iii) treatment that otherwise renders such unsecured claim unimpaired pursuant to section 1124 of the bankruptcy code or (iv) such other, less favorable treatment that is confirmed in writing as being acceptable to such holder and to the applicable debtor.

Note 2 — Summary of Significant Accounting Policies

     Principles of Consolidation and Basis of Presentation

     Between May 14, 2003 and December 5, 2003, we operated as a debtor-in-possession under the supervision of the bankruptcy Court. Our financial statements for reporting periods within that timeframe were prepared in accordance with the provisions of Statement of Position 90-7,  “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code.”

     For financial reporting purposes, close of business on December 5, 2003, represents the date of our emergence from bankruptcy. As used herein, the following terms refer to the Company and its operations:
 	 	 	
“Predecessor Company”	 	The Company, pre-emergence from bankruptcy
The Company’s operations, January 1, 2001 — December 5, 2003	
“Reorganized NRG”	 	The Company, post-emergence from bankruptcy
The Company’s operations, December 6, 2003 — December 31, 2003	
     In January 2003, the FASB issued FASB Interpretation No. 46, “Consolidation of Variable Interest Entities,” or “FIN No. 46.” FIN No. 46 requires an enterprise’s consolidated financial statements to include subsidiaries in which the enterprise has a controlling interest. Historically, that requirement has been applied to subsidiaries in which an enterprise has a majority voting interest, but in many circumstances the enterprise’s consolidated financial statements do not include the consolidation of variable interest entities with which it has similar relationships but no majority voting interest. Under FIN No. 46, the voting interest approach is not the approach used to identify the controlling financial interest. The new rule requires that for entities to be consolidated that those assets be initially recorded at their carrying amounts at the date the requirements of the new rule first apply. If determining carrying amounts as required is impractical, then the assets are to be measured at fair value the first date the new rule applies. Any difference between the net amounts of any previously recognized interest in the newly consolidated entity should be recognized as the cumulative effect of an accounting change. In December 2003, the FASB has published a revision to Interpretation 46, or “FIN 46R”, to clarify some of the provisions of FASB Interpretation No. 46,  “Consolidation of Variable Interest Entities,”  and to exempt certain entities from its requirements. As required by SOP 90-7, we have adopted FIN No. 46R as of the adoption of Fresh Start. In connection with the adoption of FIN No. 46R, we have recorded total assets of $54.7 million and total liabilities of $47.5 million as of December 6, 2003 that were previously recorded through equity method investments. The nature of the operations consolidated consisted of hydro power facilities on the East Coast.

     The consolidated financial statements include our accounts and operations and those of our subsidiaries in which we have a controlling interest. We account for the operations of LSP-Nelson Energy LLC and NRG Nelson Turbines LLC under the cost method as they are currently in bankruptcy. All significant intercompany transactions and balances have been eliminated in consolidation. Accounting policies for all of our operations are in accordance with accounting principles generally accepted in the United States of America. As discussed in Note 13, we have investments in partnerships, joint ventures and projects. Earnings from equity in international investments are recorded net of foreign income taxes.

     Fresh Start Reporting

     In accordance with Statement of Position 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code,”  certain companies qualify for fresh start reporting in connection with their emergence from bankruptcy. Fresh start reporting is appropriate on the emergence from chapter 11 if the reorganization value of the assets of the emerging entity immediately before the date of confirmation is less than the total of all post-petition liabilities and allowed claims, and if the holders of existing voting shares

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immediately before confirmation receive less than 50 percent of the voting shares of the emerging entity. We met these requirements and adopted Fresh Start reporting resulting in the creation of a new reporting entity designated as Reorganized NRG.

     The bankruptcy court issued a confirmation order approving our Plan of reorganization on November 24, 2003. Under the requirements of SOP 90-7, the Fresh Start date is determined to be the confirmation date unless significant uncertainties exist regarding the effectiveness of the bankruptcy order. Our Plan of reorganization required completion of the Xcel Energy settlement agreement prior to emergence from bankruptcy. The Xcel Energy settlement agreement was entered into on December 5, 2003. We believe this settlement agreement was a significant contingency and thus delayed the Fresh Start date until the Xcel Energy settlement agreement was finalized on December 5, 2003.

     Under the requirements of Fresh Start, we have adjusted our assets and liabilities, other than deferred income taxes, to their estimated fair values as of December 5, 2003. As a result of marking our assets and liabilities to their estimated fair values, we determined that there was a negative reorganization value that was reallocated back to our tangible and intangible assets. Deferred taxes were determined in accordance with SFAS No. 109,  “Accounting for Income Taxes.”  The net effect of all Fresh Start adjustments resulted in a gain of $3.9 billion, which is reflected in the Predecessor Company’s results for the period January 1, 2003 through December 5, 2003. The application of the Fresh Start provisions of SOP 90-7 created a new reporting entity having no retained earnings or accumulated deficit.

     As part of the bankruptcy process we engaged an independent financial advisor to assist in the determination of our reorganized enterprise value. The fair value calculation was based on management’s forecast of expected cash flows from our core assets. Management’s forecast incorporated forward commodity market prices obtained from a third party consulting firm. A discounted cash flow calculation was used to develop the enterprise value of Reorganized NRG, determined in part by calculating the weighted average cost of capital of the Reorganized NRG. The Discounted Cash Flow, or “DCF”, valuation methodology equates the value of an asset or business to the present value of expected future economic benefits to be generated by that asset or business. The DCF methodology is a “forward looking” approach that discounts expected future economic benefits by a theoretical or observed discount rate. The independent financial advisor prepared a 30-year cash flow forecast using a discount rate of approximately 11%. The resulting reorganization enterprise value as included in the Disclosure Statement ranged from $5.5 billion to $5.7 billion. The independent financial advisor then subtracted our project level debt and made several other adjustments to reflect the values of assets held for sale, excess cash and collateral requirements to estimate a range of Reorganized NRG equity value of between $2.2 billion and $2.6 billion.

     In constructing our Fresh Start balance sheet upon our emergence from bankruptcy, we used a reorganization equity value of approximately $2.4 billion, as we believe this value to be the best indication of the value of the ownership distributed to the new equity owners. Our NRG Plan of reorganization provided for the issuance of 100,000,000 shares of NRG common stock to the various creditors resulting in a calculated price per share of $24.04. Our reorganization value of approximately $9.1 billion was determined by adding our reorganized equity value of $2.4 billion, $3.7 billion of interest bearing debt and our other liabilities of $3.0 billion. The reorganization value represents the fair value of an entity before liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after restructuring. This value is consistent with the voting creditors and Court’s approval of the Plan of Reorganization.

     Our Fresh Start adjustments consist primarily of the valuation of our existing fixed assets and liabilities, equity investments and recognition of the value of certain power sales contracts that were deemed to be significantly valuable or burdensome as either intangible assets or liabilities which will be amortized into income over the respective terms of each contract. A description of the adjustments and amounts is provided in Note 3 — Emergence from Bankruptcy and Fresh Start Reporting.

     A separate plan of reorganization was filed for our Northeast Generating and South Central Generating entities that was confirmed by the bankruptcy court on November 25, 2003, and became effective on December 23, 2003, when the final conditions of the plan were completed. In connection with Fresh Start on December 5, 2003, we continued to consolidate our Northeast Generating and South Central Generating entities, as we believe that we continued to maintain control over the Northeast Generating and South Central Generating facilities through out the bankruptcy process. As previously stated, the Northeast Generating and South Central Generating entities emerged from bankruptcy on December 23, 2003. However, since the creditors received full recovery, the liabilities are not recorded as subject to compromise in the December 6, 2003 balance sheet.

     Due to the adoption of the Fresh Start upon our emergence from bankruptcy, the Reorganized NRG balance sheet, statement of operations and statement of cash flows have not been prepared on a consistent basis with the Predecessor Company’s financial statements and are therefore not comparable to the financial statements prior to the application of Fresh Start.

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     Nature of Operations

     We are a wholesale power generation company, primarily engaged in the ownership and operation of power generation facilities and the sale of energy, capacity and related products in the United States and internationally. We have a diverse portfolio of electric generation facilities in terms of geography, fuel type, and dispatch levels, which help us, mitigate risk. We seek to maximize operating income through the efficient procurement and management of fuel supplies and maintenance services, and the sale of energy, capacity and ancillary services into attractive spot, intermediate and long-term markets.

     Cash and Cash Equivalents

     Cash and cash equivalents include highly liquid investments (primarily commercial paper) with an original maturity of three months or less at the time of purchase.

     Restricted Cash

     Restricted cash consists primarily of funds held to satisfy the requirements of certain debt agreements and funds held within our projects that are restricted in their use.

     Inventory

     Inventory is valued at the lower of weighted average cost or market and consists principally of fuel oil, spare parts, coal, kerosene, emission allowance credits and raw materials used to generate steam.

     Property, Plant and Equipment

     Property, plant and equipment are stated at cost however impairment adjustments are recorded whenever events or changes in circumstances indicate carrying values may not be recoverable. On December 5, 2003, we recorded adjustments to the property, plant and equipment to reflect such items at fair value in accordance with Fresh Start reporting. A new cost basis was established with these adjustments. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance that do not improve or extend the life of the respective asset are charged to expense as incurred. Depreciation is computed using the straight-line method over the following estimated useful lives:
 	 	 	
Facilities and equipment	 	10-60 years	
Office furnishings and equipment	 	3-15 years	
     The assets and related accumulated depreciation amounts are adjusted for asset retirements and disposals with the resulting gain or loss included in operations.

     Asset Impairments

     Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate carrying values may not be recoverable. Such reviews are performed in accordance with SFAS No. 144,  “Accounting for the Impairment or Disposal of Long-Lived Asset.”  An impairment loss is recognized if the total future estimated undiscounted cash flows expected from an asset are less than its carrying value. An impairment charge is measured by the difference between an asset’s carrying amount and fair value. Fair values are determined by a variety of valuation methods, including appraisals, sales prices of similar assets and present value techniques.

     Investments accounted for by the equity method are reviewed for impairment in accordance with APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.”  APB Opinion No. 18 requires that a loss in value of an investment that is other than a temporary decline should be recognized. We identify and measure losses in value of equity investments based upon a comparison of fair value to carrying value.

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     Discontinued Operations

     Long-lived assets are classified as discontinued operations when all of the required criteria specified in SFAS No. 144 are met. These criteria include, among others, existence of a qualified plan to dispose of an asset, an assessment that completion of a sale within one year is probable and approval of the appropriate level of management and board of directors. Discontinued operations are reported at the lower of the asset’s carrying amount or fair value less cost to sell.

     Capitalized Interest

     Interest incurred on funds borrowed to finance projects expected to require more than three months to complete is capitalized. Capitalization of interest is discontinued when the asset under construction is ready for its intended use or when a project is terminated or construction ceased. Capitalized interest was approximately $27.2 million, $64.8 million, $15.9 thousand and $1.5 thousand in 2001, 2002, 2003 Predecessor Company and 2003 Reorganized NRG, respectively.

     Capitalized Project Costs

     Development costs and capitalized project costs include third party professional services, permits, and other costs that are incurred incidental to a particular project. Such costs are expensed as incurred until an acquisition agreement or letter of intent is signed, and our Board of Directors has approved the project. Additional costs incurred after this point are capitalized. When a project begins operation, previously capitalized project costs are reclassified to equity investments in affiliates or property, plant and equipment and amortized on a straight-line basis over the lesser of the life of the project’s related assets or revenue contract period. Capitalized costs are charged to expense if a project is abandoned or management otherwise determines the costs to be unrecoverable.

     Debt Issuance Costs

     Debt issuance costs are capitalized and amortized as interest expense on a basis, which approximates the effective interest method over the terms of the related debt.

     Goodwill and Intangible Assets

     Goodwill represents the excess of the purchase price of net tangible and intangible assets acquired in business combinations over their estimated fair value. Effective January 1, 2002, we implemented SFAS No. 142,  “Goodwill and Other Intangible Assets”  or “SFAS No. 142.” Pursuant to SFAS No. 142, goodwill is not amortized but is subject to periodic impairment testing. Prior to 2002, goodwill was amortized on a straight-line basis over 20 to 30 years.

     Intangible assets represent contractual rights held by us. Intangible assets are amortized over their economic useful life and reviewed for impairment on a periodic basis. Non-amortized intangible assets, including goodwill, are tested for impairment annually and on an interim basis if an event or circumstance occurs between annual tests that might reduce the fair value of that asset.

     Income Taxes

     The Predecessor Company’s income tax provision for the period January 1, 2003 through December 5, 2003 has been recorded on the basis that separate federal income tax returns will be filed. The Reorganized NRG’s income tax provision for the period December 6, 2003 through December 31, 2003 has been recorded on the basis that we and our U.S. subsidiaries will reconsolidate for federal income tax purposes as of December 6, 2003. The income tax provision for the year ended December 31, 2002 has been recorded on the basis that we and our U.S. subsidiaries have filed a consolidated federal income tax return for the period January 1, 2002 through June 3, 2002 and filed separate federal income tax returns for the remainder of 2002.

     The Predecessor Company’s income taxes have been recorded on the basis that Xcel Energy has not included us in its consolidated federal income tax return following Xcel Energy’s acquisition of our public shares on June 3, 2002. Since we and our U.S. subsidiaries will not be included in the Xcel Energy consolidated tax group, each of our U.S. subsidiaries that is classified as a corporation for U.S. income tax purposes must file a separate federal income tax return for the periods ended December 31, 2002 and December 5, 2003.

     The Reorganized NRG is no longer owned by Xcel Energy and thus, no longer included in the Xcel Energy affiliated group. The change in ownership allows us to file a consolidated federal income tax return with our U.S. subsidiaries starting on December 6, 2003.

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     Deferred income taxes are recognized for the tax consequences in future years of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts at each year-end based on enacted tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. Income tax expense is the tax payable for the period and the change during the period in deferred tax assets and liabilities. A valuation allowance is recorded to reduce deferred tax assets to the amount more likely than not to be realized.

     Revenue Recognition

     We are primarily an electric generation company, operating a portfolio of majority-owned electric generating plants and certain plants in which our ownership interest is 50% or less and which are accounted for under the equity method. In connection with our electric generation business, we also produce thermal energy for sale to customers, principally through steam and chilled water facilities. We also collect methane gas from landfill sites, which are used for the generation of electricity. In addition, we sell small amounts of natural gas and oil to third parties.

     Electrical energy revenue is recognized upon delivery to the customer. In certain markets, which are operated/controlled by an independent system operator and in which we have entered into a netting agreement with the ISO, which results in our receiving a netted invoice, we have recorded purchased energy as an offset against revenues received upon the sale of such energy. Capacity and ancillary revenue is recognized when contractually earned. Disputed revenues are not recorded in the financial statements until disputes are resolved and collection is assured.

     Revenue from long-term power sales contracts that provide for higher pricing in the early years of the contract are recognized in accordance with Emerging Issues Task Force Issue No. 91-6,  “Revenue Recognition of Long Term Power Sales Contracts.”  This results in revenue deferrals and recognition on a levelized basis over the term of the contract.

     We provide contract operations and maintenance services to some of our non-consolidated affiliates. Revenue is recognized as contract services are performed.

     We recognize other income for interest income on loans to our non-consolidated affiliates, as the interest is earned and realizable.

     Foreign Currency Translation and Transaction Gains and Losses

     The local currencies are generally the functional currency of our foreign operations. Foreign currency denominated assets and liabilities are translated at end-of-period rates of exchange. Revenues, expenses and cash flows are translated at weighted-average rates of exchange for the period. The resulting currency translation adjustments are accumulated and reported as a separate component of stockholders’ equity and are not included in the determination of the results of operations. Foreign currency transaction gains or losses are reported in results of operations. We recognized foreign currency transaction gains (losses) of $1.8 million, $(10.4) million, $(19.8) million and $0.4 million in 2001, 2002, 2003 Predecessor Company and 2003 Reorganized NRG, respectively.

     Concentrations of Credit Risk

     Financial instruments, which potentially subject us to concentrations of credit risk, consist primarily of cash, accounts receivable, notes receivable and investments in debt securities. Cash accounts are generally held in Federally insured banks. Accounts receivable, notes receivable and derivative instruments are concentrated within entities engaged in the energy industry. These industry concentrations may impact our overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. Receivables are generally not collateralized; however, we believe the credit risk posed by industry concentration is offset by the diversification and creditworthiness of our customer base.

     Fair Value of Financial Instruments

     The carrying amount of cash and cash equivalents, receivables, accounts payables, and accrued liabilities approximate fair value because of the short maturity of these instruments. The carrying amounts of long-term receivables approximate fair value, as the effective rates for these instruments are comparable to market rates at year-end, including current portions. The fair value of long-term debt is estimated based on quoted market prices for those instruments which are traded or on a present value method using current interest rates for similar instruments with equivalent credit quality.

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     Pensions

     The determination of our obligation and expenses for pension benefits is dependent on the selection of certain assumptions. These assumptions determined by management include the discount rate, the expected rate of return on plan assets and the rate of future compensation increases. Our actuarial consultants use assumptions for such items as retirement age. The assumptions used may differ materially from actual results, which may result in a significant impact to the amount of pension obligation or expense recorded by us.

     Stock Based Compensation

     During the fourth quarter of 2003, in accordance with SFAS Statement No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure”  we adopted SFAS No. 123 under the prospective transition method which requires the application of the recognition provisions to all employee awards granted, modified, or settled after the beginning of the fiscal year in which the recognition provisions are first applied. As a result, we applied the fair value recognition provisions of SFAS No. 123 as of January 1, 2003. As discussed in Note 18, we recognized compensation expense for the grants issued under the Long-Term Incentive Plan.

     Net Income Per Share

     Basic net income per share is calculated based on the weighted average of common shares outstanding during the period. Net income per share, assuming dilution is computed by dividing net income by the weighted average number of common and common equivalent shares outstanding. Our only common equivalent shares are those that result from dilutive common stock options and restricted stock.

     Use of Estimates

     The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

     In recording transactions and balances resulting from business operations, we use estimates based on the best information available. Estimates are used for such items as plant depreciable lives, tax provisions, un- collectible accounts, actuarially determined benefit costs and the valuation of long-term energy commodities contracts, among others. In addition, estimates are used to test long-lived assets for impairment and to determine fair value of impaired assets. As better information becomes available (or actual amounts are determinable), the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

     Reclassifications

     Certain prior-year amounts have been reclassified for comparative purposes. These reclassifications had no effect on our net income or total stockholders’ equity as previously reported.

     Recent Accounting Developments

     As part of the provisions of SOP 90-7, we are required to adopt, for the current reporting period, all accounting guidance that is effective within a twelve-month period. As a result, we have adopted all provisions of FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities” .

Note 3 — Emergence from Bankruptcy and Fresh Start Reporting

     In accordance with the requirements of SOP 90-7, we determined the reorganization value of NRG and subsidiaries emerging from bankruptcy to be approximately $9.1 billion. Reorganization value generally approximates fair value of the entity before considering liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after the restructuring. Several methods are used to determine the reorganization value; however, generally it is determined by discounting future cash flows for the reconstituted business that will emerge from chapter 11 bankruptcy. Our approach was consistent in that our independent financial advisor’s estimated reorganization enterprise value of our ongoing projects using a discounted cash flow approach.

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     We allocated the reorganization value of $9.1 billion to our assets in conformity with the procedures specified by SFAS No. 141. We used a third party to complete an independent appraisal of our tangible assets, equity investments and intangible assets and contracts. In completing the fair value allocation our assets were calculated to be greater than the reorganization value. As a result, we reallocated the negative reorganization value to our tangible and intangible assets in accordance with SFAS No. 141. In preparing our balance sheet we also recorded each liability existing at the plan confirmation date, other than deferred taxes, at the present value of amounts to be paid determined at appropriate current interest rates. Deferred taxes were reported in conformity with generally accepted accounting principles under SFAS No. 109. Our equity was recorded at approximately $2.4 billion representing a price per share of $24.04 for the issuance of 100,000,000 shares of common stock with bankruptcy emergence. We pushed down the effects of fresh start reporting to all of our subsidiaries.

     In constructing our Fresh Start balance sheet using our reorganization value upon our emergence from bankruptcy we used a reorganization equity value of approximately $2.4 billion, as we believe this value to be the best indication of the value of the ownership distributed to the new equity owners. Accordingly, our reorganization value of $9.1 billion was determined by adding our reorganized equity value of $2.4 billion, $3.7 billion of interest bearing debt and our other liabilities of $3.0 billion. This value is consistent with the voting creditors and Court’s approval of the Plan of Reorganization.

     The determination of the enterprise value and the allocations to the underlying assets and liabilities were based on a number of estimates and assumptions, which are inherently subject to significant uncertainties and contingencies.

     We recorded approximately $3.9 billion of net reorganization income in the Predecessor Company’s statement of operations for 2003, which includes the gain on the restructuring of debt and equity and the discharge of obligations subject to compromise for less than recorded amounts, as well as adjustments to the historical carrying values of our assets and liabilities to fair market value.

     Due to the adoption of Fresh Start as of December 5, 2003, the Reorganized NRG balance sheet, statement of operations and statement of cash flows have not been prepared on a consistent basis with the Predecessor Company’s financial statements and are not comparable in certain respects to the financial statements prior to the application of Fresh Start. A black line has been drawn on the accompanying Consolidated Financial Statements to separate and distinguish between Reorganized NRG and the Predecessor Company. The effects of the reorganization and Fresh Start on our balance sheet as of December 5, 2003, were as follows (in thousands):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Reorganized	
 	 	Company	 	Debt Discharge	 	 	 	 	 	 	 	 	 	 	 	 	 	NRG	
 	 	December 5,	 	and Exchange of	 	 	 	 	 	 	 	 	 	 	 	 	 	December 6,	
 	 	2003

	 	Stock

	 	Fresh Start Adjustments

	 	Consolidation

	 	2003

	
Current Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	396,018	 	 	$	(1,728	)(B)	 	$	 	 	 	$	 	 	 	$	1,692	(T)	 	$	395,982	 	
Restricted cash	 	 	489,383	 	 	 	1,732	(B)	 	 	 	 	 	 	 	 	 	 	1,932	(T)	 	 	493,047	 	
Accounts receivable — trade, net	 	 	208,677	 	 	 	 	 	 	 	(2	)(B)	 	 	3,627	(J)	 	 	1,177	(T)	 	 	213,479	 	
Accounts receivable — affiliates	 	 	41,259	 	 	 	 	 	 	 	819	(B)	 	 	(42,078	)(J)	 	 	 	 	 	 	—	 	
Xcel Energy settlement receivable	 	 	 	 	 	 	640,000	(A)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	640,000	 	
Current portion of notes receivable	 	 	66,628	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	66,628	 	
Inventory	 	 	233,185	 	 	 	 	 	 	 	(25,945	)(K)	 	 	(11,004	)(L)	 	 	 	 	 	 	196,236	 	
Derivative instruments valuation	 	 	161	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	161	 	
Prepayments and other current assets	 	 	156,841	 	 	 	(25,855	)(B)	 	 	(7,309	)(M)	 	 	85,873	(J)	 	 	1,047	(T)	 	 	210,597	 	
Current assets — discontinued operations	 	 	126,132	 	 	 	 	 	 	 	(1,241	)(K)	 	 	1,629	(J)	 	 	 	 	 	 	126,520	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total current assets	 	 	1,718,284	 	 	 	614,149	 	 	 	(33,678	)	 	 	38,047	 	 	 	5,848	 	 	 	2,342,650	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Property, Plant and Equipment	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net property, plant and equipment	 	 	5,247,375	 	 	 	 	 	 	 	(1,153,101	)(I)	 	 	(132,128	)(J)	 	 	46,652	(T)	 	 	4,008,798	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Other Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Equity investments in affiliates	 	 	956,757	 	 	 	 	 	 	 	(216,029	)(C)	 	 	14	(J)	 	 	(6,880	)(T)	 	 	733,862	 	
Notes receivable, less current portion — affiliates	 	 	164,987	 	 	 	 	 	 	 	(39,336	)(P)	 	 	 	 	 	 	 	 	 	 	125,651	 	
Notes receivable, less current portion	 	 	752,847	 	 	 	(155,477	)(D)	 	 	77,862	(P)	 	 	 	 	 	 	(301	)(T)	 	 	674,931	 	
Decommissioning fund investments	 	 	4,787	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	4,787	 	
Intangible assets, net	 	 	70,275	 	 	 	 	 	 	 	437,222	(O)	 	 	(22,829	)(I)	 	 	 	 	 	 	484,668	 	
Debt issuance costs, net	 	 	67,045	 	 	 	 	 	 	 	(67,045	)(P)	 	 	 	 	 	 	 	 	 	 	—	 	
Derivative instruments valuation	 	 	66,442	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	66,442	 	
Other assets	 	 	18,268	 	 	 	 	 	 	 	(37,891	)(P)	 	 	98,857	(J)	 	 	2,170	(T)	 	 	112,890	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	31,486	(J)	 	 	 	 	 	 	 	 	
Non-current assets — discontinued operations	 	 	822,569	 	 	 	 	 	 	 	(209,919	)(P)	 	 	 	 	 	 	 	 	 	 	612,650	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total other assets	 	 	2,923,977	 	 	 	(155,477	)	 	 	(55,136	)	 	 	107,528	 	 	 	(5,011	)	 	 	2,815,881	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total Assets	 	$	9,889,636	 	 	$	458,672	 	 	$	(1,241,915	)	 	$	13,447	 	 	$	47,489	 	 	$	9,167,329	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	

 	 	Predecessor	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Reorganized	
 	 	Company	 	Debt Discharge	 	 	 	 	 	 	 	 	 	 	 	 	 	NRG	
 	 	December 5,	 	and Exchange of	 	 	 	 	 	 	 	 	 	 	 	 	 	December 6,	
 	 	2003

	 	Stock

	 	Fresh Start Adjustments

	 	Consolidation

	 	2003

	
Current Liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current portion of long-term debt	 	$	1,433,551	 	 	$	(155,477	)(D)	 	$	(89,182	)(P)	 	$	1,307,249	(Q)	 	$	613	(T)	 	$	2,496,754	 	
Short-term debt	 	 	 	 	 	 	 	 	 	 	18,645	(P)	 	 	 	 	 	 	 	 	 	 	18,645	 	
Accounts payable — trade	 	 	299,409	 	 	 	(101,632	)(E)	 	 	(805	)(N)	 	 	5,499	(J)	 	 	 	 	 	 	202,471	 	
Accounts payable — affiliates	 	 	21,457	 	 	 	(2,308	)(B)	 	 	(5,192	)(N)	 	 	2,995	(J)	 	 	36	(T)	 	 	16,988	 	
Accrued income tax	 	 	19,303	 	 	 	 	 	 	 	(7,127	)(M)	 	 	4,255	(J)	 	 	 	 	 	 	16,431	 	
Accrued property, sales and other taxes	 	 	30,200	 	 	 	 	 	 	 	(5,942	)(B)	 	 	3,556	(J)	 	 	 	 	 	 	27,814	 	
Accrued salaries, benefits and related costs	 	 	14,195	 	 	 	 	 	 	 	 	 	 	 	2,519	(J)	 	 	5	(T)	 	 	16,719	 	
Accrued interest	 	 	76,485	 	 	 	(2,464	)(B)	 	 	 	 	 	 	1,631	(J)	 	 	121	(T)	 	 	75,773	 	
Derivative instruments valuation	 	 	95	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	95	 	
Creditor pool obligation	 	 	 	 	 	 	1,040,000	(F)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	1,040,000	 	
Other bankruptcy settlement	 	 	 	 	 	 	220,000	(F)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	220,000	 	
Other current liabilities	 	 	135,275	 	 	 	57	(F)	 	 	11,800	(O)	 	 	(10,770	)(J)	 	 	413	(T)	 	 	136,775	 	
Current liabilities — discontinued operations	 	 	160,648	 	 	 	 	 	 	 	(51,679	)(J)	 	 	6	(J)	 	 	 	 	 	 	108,975	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total current liabilities	 	 	2,190,618	 	 	 	998,176	 	 	 	(129,482	)	 	 	1,316,940	 	 	 	1,188	 	 	 	4,377,440	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Other Liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term debt	 	 	849,192	 	 	 	10,000	(G)	 	 	(21,869	)(P)	 	 	303	(J)	 	 	42,060	(T)	 	 	879,686	 	
Deferred income taxes	 	 	146,120	 	 	 	 	 	 	 	(13,973	)(M)	 	 	12,541	(J)	 	 	 	 	 	 	144,688	 	
Postretirement and other benefit obligations	 	 	44,601	 	 	 	(1,118	)(B)	 	 	64,067	(R)	 	 	(2,838	)(J)	 	 	 	 	 	 	104,712	 	
Derivative instruments valuation	 	 	53,082	 	 	 	 	 	 	 	 	 	 	 	102,627	(J)	 	 	 	 	 	 	155,709	 	
Other long-term obligations	 	 	146,761	 	 	 	763	(B)	 	 	488,218	(O)	 	 	(99,060	)(J)	 	 	 	 	 	 	536,682	 	
Non-current liabilities — discontinued operations	 	 	558,194	 	 	 	 	 	 	 	1,366	(M)	 	 	 	 	 	 	 	 	 	 	559,560	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total non-current liabilities	 	 	1,797,950	 	 	 	9,645	 	 	 	517,809	 	 	 	13,573	 	 	 	42,060	 	 	 	2,381,037	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total liabilities not subject to compromise	 	 	3,988,568	 	 	 	1,007,821	 	 	 	388,327	 	 	 	1,330,513	 	 	 	43,248	 	 	 	6,758,477	 	
Total liabilities subject to compromise	 	 	7,658,071	 	 	 	(6,278,547	)(H)	 	 	(1,367	)(J)	 	 	(1,378,157	)(Q)	 	 	 	 	 	 	—	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total liabilities	 	 	11,646,639	 	 	 	(5,270,726	)	 	 	386,960	 	 	 	(47,644	)	 	 	43,248	 	 	 	6,758,477	 	
Minority interest	 	 	611	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	4,241	(T)	 	 	4,852	 	
Commitments and Contingencies	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Stockholders’ Equity/Deficit	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Class A — Common stock; $.01 par value; 100 shares authorized in 2002; 3 shares issued and outstanding at December 31, 2002	 	 	1	 	 	 	(1	)(S)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	—	 	
Common stock; $.01 par value; 100 authorized in 2002; 1 share issued and outstanding at December 31, 2002	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	—	 	
Common stock; $.01 par value; 500,000,000 authorized in 2003; 100,000,000 shares issued and outstanding at December 6, 2003	 	 	—	 	 	 	1,000	(H)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	1,000	 	
Additional paid-in capital	 	 	2,227,691	 	 	 	2,403,000	(H)	 	 	(2,227,691	)(S)	 	 	 	 	 	 	 	 	 	 	2,403,000	 	
Retained earnings/deficit	 	 	(3,986,739	)	 	 	 	 	 	 	3,924,215	(S)	 	 	62,524	(S)	 	 	 	 	 	 	—	 	
Accumulated other comprehensive income (loss)	 	 	1,433	 	 	 	 	 	 	 	 	 	 	 	(1,433	)(S)	 	 	 	 	 	 	—	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total stockholders’ equity/(deficit)	 	 	(1,757,614	)	 	 	2,403,999	 	 	 	1,696,524	 	 	 	61,091	 	 	 	—	 	 	 	2,404,000	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total Liabilities and Stockholders’ Equity/Deficit	 	$	9,889,636	 	 	$	(2,866,727	)	 	$	2,083,484	 	 	$	13,447	 	 	$	47,489	 	 	$	9,167,329	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
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(A)	 	Represents a $640.0 million receivable from Xcel Energy that relates to the Xcel Energy Settlement Agreement. $288.0 million was paid on February 20, 2004 in cash and $352.0 million will be paid on April 30, 2004.	
 	 	 	
(B)	 	Adjustments to assets and liabilities resulting from the NRG Energy bankruptcy settlement.	
 	 	 	
(C)	 	Includes the adjustment of carrying amount of Investments in Projects to fair market value as determined by independent appraisers.	
 	 	 	
(D)	 	The NRG Energy bankruptcy settlement included the liquidation of NRG FinCo. As a result, the NRG FinCo creditors obtained a perfected first priority security interest in all of LSP Pike Energy LLC assets, making the Mississippi Industrial Revenue Bonds owed by LSP Pike Energy LLC worthless.	
 	 	 	
(E)	 	Includes $103.0 million discharge of obligations related to LSP Pike Energy LLC settlement with Shaw Constructors, Inc.	
 	 	 	
(F)	 	Includes the establishment of a creditor’s pool and the FinCo lender settlement:	

Creditor installment payments	 	$	515.0	 	
Establishment of plan of reorganization liability	 	 	500.0	 	
Contingency payment	 	 	25.0	 	
FinCo lender settlement (see note 24)	 	 	220.0	 	

 	 	
Total other current liabilities	 	$	1,260.0	 	

 	 	
(G)	 	Represents NRG Energy Promissory Note owed to Xcel Energy, due June 5, 2006 with a stated interest rate of 3.0%	
 	 	 	
(H)	 	Represents the elimination of approximately $5.2 billion of corporate level bank and bond debt and approximately $1.1 billion of additional claims and disputes by distributing a combination of equity and up to $1.04 billion in cash among our unsecured creditors. Upon reorganization we issued 100 million shares of NRG common stock at $24.04 per share.	
 	 	 	
(I)	 	Result of allocating the reorganization value in conformity with the purchase method of accounting for business combinations. These allocations were based on valuations obtained from independent appraisers.	
 	 	 	
(J)	 	Adoption of Fresh Start Reporting and reinstatement of miscellaneous liabilities subject to compromise.	
 	 	 	
(K)	 	Accounting policy change upon adoption of fresh start reporting. Consumables are no longer included as inventory and are expensed as incurred.	
 	 	 	
(L)	 	Accounting policy change upon adoption of fresh start reporting. Capital spares were reclassified from inventory to Property Plant and Equipment.	
 	 	 	
(M)	 	Records income taxes of the Company based on the guidance provided in the Statement of Financial Accounting Standards No. 109 and SOP 90-7.	
 	 	 	
(N)	 	Adjust assets and liabilities to reflect management’s estimate, with the assistance of independent specialists, of the fair value.	
 	 	 	
(O)	 	Reflects management’s estimate, with the assistance of independent appraisers, of the fair value of power purchase agreements and SO(2) emission credits. Management identified certain power purchase agreements that were either significantly valuable or significantly burdensome as compared to our market expectations. The predecessor goodwill and intangibles were written off. Our guarantees were reviewed for the requirement to recognize a liability at inception. As a result, we recorded a $15.0 million liability. In addition, our Asset Retirement Obligation or “ARO” was revalued.	
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SO(2) emission credits	$	373.5	 	
Valuable contracts	 	111.2	 	
Predecessor intangible	 	(47.5	)	

 	 	
Total Intangible	$	437.2	 	

 	 	
Burdensome contracts	$	15.1	 	
Other valuations adjustments	 	(3.3	)	

 	 	
Total other current liabilities	$	11.8	 	

 	 	
Burdensome contracts	$	467.2	 	
Other valuations adjustments	 	21.0	 	

 	 	
Total other long-term obligations	$	488.2	 	

 	 	
(P)	 	Reflects management’s estimate, based on current market interest rates as of December 5, 2003, of the fair value of notes receivable, notes payable and other debt instruments.	
 	 	 	
(Q)	 	Reclassification of subject to compromise liabilities due to emergence from bankruptcy consists primarily of the debt held at our Northeast and South Central subsidiaries of $1.3 billion. The remaining amounts were reclassified to current liabilities.	
 	 	 	
(R)	 	Adjustment to post-retirement and other benefit obligations in order to reflect the accumulated benefit obligation liability based on independent actuarial reports. The pension and welfare plans were assumed from Xcel Energy without the transfer of assets.	
 	 	 	
(S)	 	Reflects the cancellation of the Predecessor Company’s common stock and the elimination of the retained deficit and the accumulated other comprehensive loss.	
 	 	 	
(T)	 	As required by SOP 90-7, we have adopted FASB Interpretation No. 46 “Consolidation of Variable Interest Entities,”  or “FIN 46,” as of the adoption of Fresh Start. The adoption of FIN 46 resulted in the consolidation of Northbrook New York, LLC and Northbrook Energy, LLC.	
     APB No. 18, “The Equity Method of Accounting for Investments in Common Stock”, requires us to effectively push down the effects of Fresh Start reporting to our unconsolidated equity method investments and to recognize an adjustment to our share of the earnings or losses of an investee as if the investee was a consolidated subsidiary. As a result of pushing down the impact of Fresh Start to our West Coast Power affiliate we determined that a contract based intangible asset with a one year remaining life, consisting of the value of West Coast Power’s California Department of Water Resources energy sales contract, must be established and recognized as a basis adjustment to our share of the future earnings generated by West Coast Power. This adjustment will reduce our equity earnings in the amount of approximately $10.4 million per month during 2004 until the contract expires in December 2004.

Note 4 — Financial Instruments

     The estimated fair values of our recorded financial instruments are as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor Company

	 	Reorganized NRG

	
 	 	December 31, 2002

	 	December 6, 2003

	 	December 31, 2003

	
 	 	Carrying	 	 	 	 	 	Carrying	 	 	 	 	 	Carrying	 	 	
 	 	Amount

	 	Fair Value

	 	Amount

	 	Fair Value

	 	Amount

	 	Fair Value

	
 	 	(In thousands)	
Cash and cash equivalents	 	$	360,860	 	 	$	360,860	 	 	$	395,982	 	 	$	395,982	 	 	$	551,223	 	 	$	551,223	 	
Restricted cash	 	 	211,966	 	 	 	211,966	 	 	 	493,047	 	 	 	493,047	 	 	 	116,067	 	 	 	116,067	 	
Notes receivable, including current portion	 	 	990,695	 	 	 	990,695	 	 	 	867,210	 	 	 	867,210	 	 	 	886,937	 	 	 	886,937	 	
Long-term debt, including current portion	 	 	7,782,648	 	 	 	5,491,081	 	 	 	3,376,440	 	 	 	3,376,440	 	 	 	4,129,011	 	 	 	4,186,136	 	
     For cash and cash equivalents and restricted cash, the carrying amount approximates fair value because of the short-term maturity of those instruments. The fair value of notes receivable is based on expected future cash flows discounted at market interest rates. The fair value of long-term debt is estimated based on quoted market prices for those instruments which are traded or on a present value method using current interest rates for similar instruments with equivalent credit quality.

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Note 5 — Debtors’ Statements

     As stated above, we and certain of our subsidiaries filed voluntary petitions for reorganization under chapter 11 of the Bankruptcy Code during 2003. On December 5, 2003, we and five of our subsidiaries emerged from bankruptcy. As of the respective bankruptcy filing dates, the Debtors’ financial records were closed for the Prepetition Period. As required by SOP 90-7  “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code” , below are the condensed combined financial statements of our remaining Debtors since the date of the bankruptcy filings, “the Debtors’ Statements.”

     The Debtors’ Statements consist of the following wholly-owned consolidated entities which remained in bankruptcy as of December 6, 2003: Arthur Kill Power LLC, Astoria Gas Turbine Power LLC, Berrians I Gas Turbine Power, LLC, Big Cajun II Unit 4 LLC, Connecticut Jet Power LLC, Devon Power LLC, Dunkirk Power LLC, Huntley Power LLC, Louisiana Generating LLC, LSP-Nelson Energy LLC, Middletown Power LLC, Montville Power LLC, Northeast Generation Holding LLC, Norwalk Power LLC, NRG Central US LLC, NRG Eastern LLC, NRG McClain LLC, NRG Nelson Energy LLC, NRG New Roads Holdings LLC, NRG Northeast Generating LLC, NRG South Central Generating LLC, Oswego Harbor Power LLC, Somerset Power LLC, and South Central Generation Holding LLC. As of December 31, 2003, three entities remain in bankruptcy. Two entities have been deconsolidated and accounted for under the cost method because we have effectively lost control of those entities including NRG Nelson Turbine, LLC and LSP-Nelson Energy LLC. The other entity, NRG McClain LLC, is shown as a discontinued operation since it was held for sale prior to filing for bankruptcy.

Debtors’ Condensed Combined Statement of Operations
 	 	 	 	 	
 	 	For the Period	
 	 	May 15, 2003 -	
 	 	December 5,	
 	 	2003

	
 	 	(In thousands)	
Operating revenue	 	$	731,413	 	
Operating costs and expenses	 	 	620,199	 	
Fresh start reporting adjustments — asset write-downs, net	 	 	1,244,016	 	
Reorganization items	 	 	27,158	 	
Restructuring and impairment charges	 	 	23,359	 	

 	 	
Operating loss	 	 	(1,183,319	)	
Other expense	 	 	(160,246	)	

 	 	
Net loss	 	$	(1,343,565	)	

 	 	
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Debtors’ Condensed Combined Balance Sheet
 	 	 	 	 	
 	 	December 6,	
 	 	2003

	
 	 	(In thousands)	
ASSETS	 	 	 	 	
Cash	 	$	16,421	 	
Accounts receivables-trade	 	 	38,018	 	
Accounts receivables, non-Debtor affiliates	 	 	31,019	 	
Inventory	 	 	150,618	 	
Current portion of notes receivable	 	 	1,500	 	
Other current assets	 	 	183,433	 	

 	 	
Total current assets	 	 	421,009	 	
Property, plant and equipment, net	 	 	1,829,118	 	
Investment in non-Debtors	 	 	573	 	
Intangible assets, net	 	 	335,851	 	
Other assets	 	 	191,257	 	

 	 	
Total assets	 	$	2,777,808	 	

 	 	
LIABILITIES AND STOCKHOLDERS’ EQUITY	 	 	 	 	
Accounts payable-trade	 	$	18,809	 	
Debt Obligation	 	 	1,307,250	 	
Other current liabilities	 	 	74,143	 	

 	 	
Total current liabilities	 	 	1,400,202	 	
Other long-term obligations	 	 	715,454	 	
Total stockholders’ equity	 	 	662,152	 	

 	 	
Total liabilities and stockholders’ equity	 	$	2,777,808	 	

 	 	
Debtors’ Condensed Combined Statement of Cash Flows
 	 	 	 	 	
 	 	For the Period	
 	 	May 15, 2003 -	
 	 	December 5,	
 	 	2003

	
 	 	(In thousands)	
Net cash provided by operating activities	 	$	65,951	 	
Net cash used by investing activities	 	 	(72,667	)	
Net cash used by financing activities	 	 	—	 	

 	 	
Net increase in cash and cash equivalents	 	 	(6,716	)	
Cash and cash equivalents at beginning of period	 	 	23,137	 	

 	 	
Cash and cash equivalents at end of period	 	$	16,421	 	

 	 	
Note 6 — Discontinued Operations

     SFAS No. 144 requires that discontinued operations be valued on an asset-by-asset basis at the lower of carrying amount or fair value less costs to sell. In applying those provisions our management considered cash flow analyses, bids and offers related to those assets and businesses. This amount is included in income/(loss) on discontinued operations, net of income taxes in the accompanying Statement of Operations. In accordance with the provisions of SFAS No. 144, assets held for sale will not be depreciated commencing with their classification as such.

     We have classified certain business operations, and gains/losses recognized on sale, as discontinued operations for projects that were sold or have met the required criteria for such classification.

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     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.

     Summarized results of operations of the discontinued operations were as follows. For the years ended December 31, 2001 and December 31, 2002, discontinued results of operations included our Crockett Cogeneration, Bulo Bulo, Csepel, Entrade, Killingholme, NLGI, McClain, TERI, NEO Corporation projects, Cahua, Energia Pacasmayo, PERC, Cobee, LSP Energy and Hsin Yu. For the period from January 1, 2003 to December 5, 2003, discontinued results of operations include our Killingholme, McClain, NLGI, NEO Corporation projects, TERI, Cahua, Energia Pacasmayo, PERC, Cobee, LSP Energy and Hsin Yu projects. For the period December 6, 2003 to December 31, 2003, discontinued results of operations include our McClain, PERC, Cobee, LSP Energy and Hsin Yu projects. During the first quarter 2004 we determined that PERC and Cobee met the criteria for discontinued operations, accordingly all periods presented have been restated. During the second quarter 2004 we determined that LSP Energy and Hsin Yu met the criteria for discontinued operations, accordingly all periods presented have been restated.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor Company

	 	Reorganized NRG

	
 	 	 	 	 	 	 	 	 	 	For the Period	 	For the Period	
 	 	Year Ended December 31,

	 	January 1 -
December 5,	 	December 6 -
December 31,	
Description

	 	2001

	 	2002

	 	2003

	 	2003

	
 	 	 	 	 	 	(In thousands)	 	 	 	 	
Operating revenues	 	$	713,011	 	 	$	982,007	 	 	$	263,177	 	 	$	19,178	 	
Operating and other expenses	 	 	662,425	 	 	 	1,667,705	 	 	 	617,671	 	 	 	19,480	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Pre-tax income/(loss) from operations of discontinued components	 	 	50,586	 	 	 	(685,698	)	 	 	(354,494	)	 	 	(302	) 	
Income tax expense/(benefit)	 	 	(4,569	)	 	 	(6,810	)	 	 	(21,868	)	 	 	10	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Income/(loss) from operations of discontinued components	 	 	55,155	 	 	 	(678,888	)	 	 	(332,626	)	 	 	(312	) 	
Disposal of discontinued components — pre-tax gain (net)	 	 	—	 	 	 	2,814	 	 	 	151,809	 	 	 	—	 	
Income tax benefit	 	 	—	 	 	 	(2,992	)	 	 	—	 	 	 	—	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Disposal of discontinued components — gain (net)	 	 	—	 	 	 	5,806	 	 	 	151,809	 	 	 	—	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Net income/(loss) on discontinued operations	 	$	55,155	 	 	$	(673,082	)	 	$	(180,817	)	 	$	(312	) 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
     Operating and other expenses for 2001 and 2002 shown in the table above included asset impairment charges of $0 and approximately $502.0 million, respectively. The 2002 charges are comprised of approximately $477.9 million for the Killingholme project, $121.9 million for the Hsin Yu project, $64.7 million for the Batesville turbine project, $12.4 million for the NEO Landfill Gas, Inc. project and $11.7 million for the TERI project. Operating and other expenses for 2003 include asset impairment charges of approximately $124.3 million, comprised of approximately $100.7 million for McClain and $23.6 million for NLGI.

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     The components of income tax benefit attributable to discontinued operations were as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor Company

	 	Reorganized NRG

	
 	 	 	 	 	 	 	 	 	 	For the Period	 	For the Period	
 	 	Year Ended December 31,

	 	January 1 -
December 5,	 	December 6 -
December 31,	
Discontinued Operations:

	 	2001

	 	2002

	 	2003

	 	2003

	
 	 	(In thousands)	
Current	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
U.S	 	$	509	 	 	$	935	 	 	$	(6	)	 	$	—	 	
Foreign	 	 	(2,876	)	 	 	(5,126	)	 	 	(831	)	 	 	10	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
 	 	 	(2,367	)	 	 	(4,191	)	 	 	(837	)	 	 	10	 	
Deferred	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
U.S	 	 	(45	)	 	 	(1,947	)	 	 	—	 	 	 	—	 	
Foreign	 	 	9,439	 	 	 	(672	)	 	 	(21,031	)	 	 	—	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
 	 	 	9,394	 	 	 	(2,619	)	 	 	(21,031	)	 	 	—	 	
Section 29 tax credits	 	 	(11,596	)	 	 	—	 	 	 	—	 	 	 	—	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
 	 	 	(4,569	)	 	 	(6,810	)	 	 	(21,868	)	 	 	10	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Disposal of discontinued components — gain (net)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
U.S	 	 	—	 	 	 	(2,992	)	 	 	—	 	 	 	—	 	
Foreign	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
 	 	 	—	 	 	 	(2,992	)	 	 	—	 	 	 	—	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total income tax expense/(benefit)	 	$	(4,569	)	 	$	(9,802	)	 	$	(21,868	)	 	$	10	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
     The assets and liabilities of the discontinued operations are reported in the December 31, 2003, December 6, 2003 and December 31, 2002 balance sheets as discontinued operations. The major classes of assets and liabilities are presented by geographic area in the following table. As of December 6, 2003 and December 31, 2003, within our Power Generation segment, the PERC, McClain and LSP Energy projects are included in the Other North America classification and the Cobee and Hsin Yu projects are included in the Other International classification. As of December 31, 2002, within our power generation segment, the PERC, McClain and LSP Energy projects are included in the Other North America classification and the Killingholme, Cahua, Pacasmayo, Cobee and Hsin Yu projects are included in the Other International classification. The NEO and TERI projects are included in the Alternative Energy classification.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG	
 	 	Power Generation

	
 	 	December 6, 2003

	 	December 31, 2003

	
 	 	Other	 	 	 	 	 	 	 	 	 	Other	 	 	 	 	
 	 	North	 	Other	 	 	 	 	 	North	 	Other	 	 	
 	 	America

	 	International

	 	Total

	 	America

	 	International

	 	Total

	
 	 	(In thousands)	
Cash and cash equivalents	 	$	4,994	 	 	$	8,597	 	 	$	13,591	 	 	$	4,292	 	 	$	8,264	 	 	$	12,556	 	
Restricted cash	 	 	56,848	 	 	 	—	 	 	 	56,848	 	 	 	60,292	 	 	 	—	 	 	 	60,292	 	
Receivables, net	 	 	13,193	 	 	 	13,111	 	 	 	26,304	 	 	 	12,676	 	 	 	11,259	 	 	 	23,935	 	
Inventory	 	 	14,997	 	 	 	4,359	 	 	 	19,356	 	 	 	8,722	 	 	 	3,538	 	 	 	12,260	 	
Other current assets	 	 	3,979	 	 	 	6,442	 	 	 	10,421	 	 	 	3,731	 	 	 	6,787	 	 	 	10,518	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Current assets — discontinued operations	 	$	94,011	 	 	$	32,509	 	 	$	126,520	 	 	$	89,713	 	 	$	29,848	 	 	$	119,561	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Property, plant and equipment, net	 	$	481,929	 	 	$	74,714	 	 	$	556,643	 	 	$	487,753	 	 	$	75,250	 	 	$	563,003	 	
Deferred income taxes	 	 	—	 	 	 	31,486	 	 	 	31,486	 	 	 	—	 	 	 	31,469	 	 	 	31,469	 	
Other non-current assets	 	 	14,842	 	 	 	9,679	 	 	 	24,521	 	 	 	14,765	 	 	 	9,731	 	 	 	24,496	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Non-current assets — discontinued operations	 	$	496,771	 	 	$	115,879	 	 	$	612,650	 	 	$	502,518	 	 	$	116,450	 	 	$	618,968	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Current portion of long-term debt	 	$	5,945	 	 	$	48,973	 	 	$	54,918	 	 	$	6,206	 	 	$	49,744	 	 	$	55,950	 	
Accounts payable — trade	 	 	9,237	 	 	 	24,715	 	 	 	33,952	 	 	 	3,057	 	 	 	23,037	 	 	 	26,094	 	
Accrued interest	 	 	11,383	 	 	 	608	 	 	 	11,991	 	 	 	13,182	 	 	 	757	 	 	 	13,939	 	
Other current liabilities	 	 	2,157	 	 	 	5,957	 	 	 	8,114	 	 	 	8,248	 	 	 	5,946	 	 	 	14,194	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Current liabilities — discontinued operations	 	$	28,722	 	 	$	80,253	 	 	$	108,975	 	 	$	30,693	 	 	$	79,484	 	 	$	110,177	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Long-term debt	 	$	313,738	 	 	$	19,779	 	 	$	333,517	 	 	$	313,738	 	 	$	19,779	 	 	$	333,517	 	
Minority interest	 	 	31,640	 	 	 	422	 	 	 	32,062	 	 	 	31,879	 	 	 	406	 	 	 	32,285	 	
Other non-current liabilities	 	 	184,779	 	 	 	9,202	 	 	 	193,981	 	 	 	184,972	 	 	 	8,110	 	 	 	193,082	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Non-current liabilities — discontinued operations	 	$	530,157	 	 	$	29,403	 	 	$	559,560	 	 	$	530,589	 	 	$	28,295	 	 	$	558,884	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
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 	 	Predecessor Company	 	 	 	 	 	 	 	 	
 	 	Power Generation
December 31, 2002

	 	 	 	 	 	 	 	 	
 	 	Other	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	North	 	Other	 	Alternative	 	 	 	 	 	 	 	 	 	 	
 	 	America

	 	International

	 	Energy

	 	Total

	 	 	 	 	 	 	 	 	
 	(In thousands)	 	 	 	 	 	 	
Cash and cash equivalents	 	$	6,933	 	 	$	40,740	 	 	$	430	 	 	$	48,103	 	 	 	 	 	 	 	 	 	
Restricted cash	 	 	69,224	 	 	 	1,396	 	 	 	—	 	 	 	70,620	 	 	 	 	 	 	 	 	 	
Receivables, net	 	 	17,645	 	 	 	29,693	 	 	 	296	 	 	 	47,634	 	 	 	 	 	 	 	 	 	
Inventory	 	 	11,980	 	 	 	17,072	 	 	 	301	 	 	 	29,353	 	 	 	 	 	 	 	 	 	
Derivative instruments valuation	 	 	—	 	 	 	29,795	 	 	 	—	 	 	 	29,795	 	 	 	 	 	 	 	 	 	
Other current assets	 	 	2,107	 	 	 	10,526	 	 	 	294	 	 	 	12,927	 	 	 	 	 	 	 	 	 	

 	 	 	 	

	 	 	 	

 	 	 	 	

 	 	 	 	 	 	 	 	 	 	
Current assets — discontinued operations	 	$	107,889	 	 	$	129,222	 	 	$	1,321	 	 	$	238,432	 	 	 	 	 	 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	 	 	 	 	 	 	
Property, plant and equipment, net	 	$	720,458	 	 	$	535,695	 	 	$	13,114	 	 	$	1,269,267	 	 	 	 	 	 	 	 	 	
Derivative instruments valuation	 	 	—	 	 	 	87,803	 	 	 	—	 	 	 	87,803	 	 	 	 	 	 	 	 	 	
Other non-current assets	 	 	12,015	 	 	 	20,118	 	 	 	18,531	 	 	 	50,664	 	 	 	 	 	 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	 	 	 	 	 	 	
Non-current assets — discontinued operations	 	$	732,473	 	 	$	643,616	 	 	$	31,645	 	 	$	1,407,734	 	 	 	 	 	 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	 	 	 	 	 	 	
Current portion of long-term debt	 	$	166,083	 	 	$	462,570	 	 	$	7,658	 	 	$	636,311	 	 	 	 	 	 	 	 	 	
Accounts payable — trade	 	 	19,321	 	 	 	47,359	 	 	 	966	 	 	 	67,646	 	 	 	 	 	 	 	 	 	
Accrued income tax	 	 	4	 	 	 	22,422	 	 	 	(166	) 	 	 	22,260	 	 	 	 	 	 	 	 	 	
Other current liabilities	 	 	18,201	 	 	 	14,689	 	 	 	3,963	 	 	 	36,853	 	 	 	 	 	 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	 	 	 	 	 	 	
Current liabilities — discontinued operations	 	$	203,609	 	 	$	547,040	 	 	$	12,421	 	 	$	763,070	 	 	 	 	 	 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	 	 	 	 	 	 	
Long-term debt	 	$	334,200	 	 	$	68,572	 	 	$	—	 	 	$	402,772	 	 	 	 	 	 	 	 	 	
Deferred income taxes	 	 	121	 	 	 	113,035	 	 	 	(2,102	) 	 	 	111,054	 	 	 	 	 	 	 	 	 	
Derivative instruments valuation	 	 	—	 	 	 	43,891	 	 	 	—	 	 	 	43,891	 	 	 	 	 	 	 	 	 	
Minority interest	 	 	28,791	 	 	 	1,344	 	 	 	216	 	 	 	30,351	 	 	 	 	 	 	 	 	 	
Other non-current liabilities	 	 	769	 	 	 	13,763	 	 	 	—	 	 	 	14,532	 	 	 	 	 	 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	 	 	 	 	 	 	
Non-current liabilities — discontinued operations	 	$	363,881	 	 	$	240,605	 	 	$	(1,886	) 	 	$	602,600	 	 	 	 	 	 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	 	 	 	 	 	 	
     Bulo Bulo — In June 2002, we began negotiations to sell our 60% interest in Compania Electrica Central Bulo Bulo S.A. (Bulo Bulo), a Bolivian corporation. The transaction reached financial close in the fourth quarter of 2002 resulting in cash proceeds of $10.9 million (net of cash transferred of $8.6 million) and a loss of $10.6 million.

     Crockett Cogeneration Project — In September 2002, we announced that we had reached an agreement to sell our 57.7% interest in the Crockett Cogeneration Project, a 240 MW natural gas fueled cogeneration plant near San Francisco, California, to Energy Investment Fund Group, an existing LP, and a unit of GE Capital. In November 2002, the sale closed and we realized net cash proceeds of approximately $52.1 million (net of cash transferred of $0.2 million) and a loss on disposal of approximately $11.5 million.

     Csepel and Entrade — In September 2002, we announced that we had reached agreements to sell our Csepel power generating facilities (located in Budapest, Hungary) and our interest in Entrade (an electricity trading business headquartered in Prague) to Atel, an independent energy group headquartered in Switzerland. The sales of Csepel and Entrade closed before year-end and resulted in cash proceeds of $92.6 million (net of cash transferred of $44.1 million) and a gain of approximately $24.0 million. We accounted for the results of operations of Csepel and Entrade as part of our power generation segment within Europe.

     Killingholme — During third quarter 2002, we recorded an impairment charge of $477.9 million. In January 2003, we completed the sale of our interest in the Killingholme project to our lenders for a nominal value and forgiveness of outstanding debt with a carrying value of approximately $360.1 million at December 31, 2002. The sale of our interest in the Killingholme project and the release of debt obligations resulted in a gain on sale in the first quarter of 2003 of approximately $191.2 million. The gain results from the write-down of the project’s assets in the third quarter of 2002 below the carrying value of the related debt.

     NLGI — During 2002, we recorded an impairment charge of $12.4 million related to subsidiaries of NLGI, an indirect wholly owned subsidiary of NRG Energy. The charge was related largely to asset impairments based on a revised project outlook. During the quarter ended March 31, 2003, we recorded impairment charges of $23.6 million related to subsidiaries of NLGI and a charge of $14.5 million to write off our 50% investment in Minnesota Methane, LLC. Through April 30, 2003, NRG Energy and NLGI failed to make certain payments causing a default under NLGI’s term loan agreements. In May 2003, the project lenders to the wholly-owned subsidiaries of NLGI and Minnesota Methane LLC foreclosed on our membership interest in the NLGI subsidiaries and our equity interest in Minnesota Methane LLC. There was no material gain or loss recognized as a result of the foreclosure.

     TERI — During 2002, we recorded an impairment charge of $11.7 million based on a revised project outlook. In September 2003, we completed the sale of TERI, a biomass waste-fuel power plant located in Florida and a wood processing facility located in Georgia, to DG Telogia Power, LLC. The sale resulted in net proceeds of approximately $1.0 million. We entered into an agreement to sell the

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wood processing facility on behalf of DG Telogia Power, LLC. This sale was completed during fourth quarter 2003 and we received cash consideration of approximately $1.0 million, resulting in a net gain on sale of approximately $1.0 million.

     Peru Projects — In November 2003, we completed the sale of the Cahua and Pacasmayo (Peruvian Assets) resulting in net cash proceeds of approximately $16.2 million and a loss of $36.9 million. In addition, we expect to receive an additional consideration adjustment of approximately $2 million during 2004.

     NEO Corporation — In August of 1995, we entered into a Marketing, Development and Joint Proposing Agreement, or “the Marketing Agreement”, with Cambrian Energy Development LLC, or “Cambrian.” Various claims had arisen in connection with this Marketing Agreement. In November 2003, we entered into a Settlement Agreement with Cambrian where we agreed to transfer our 100% interest in three gasco projects (NEO Ft. Smith, NEO Phoenix and NEO Woodville).

     McClain — We reviewed the recoverability of our McClain assets pursuant to SFAS No. 144 and recorded a charge of $100.7 million in the second quarter of 2003. On August 14, 2003, NRG’s Board of Directors approved a plan to sell its 77% interest in McClain Generating Station, a 520 MW combined-cycle, natural gas-fired facility located in New Castle, Oklahoma. On August 18, 2003, we entered into an Asset Purchase Agreement with Oklahoma Gas & Electric Company pursuant to which we would, subject to the satisfaction of certain conditions, sell all of the McClain assets in a sale pursuant to Section 363 of the Bankruptcy Codes as part of McClain’s Chapter 11 proceeding that was subsequently filed on August 19, 2003. In accordance with Section 363 of the Bankruptcy Code and the terms of the Asset Purchase Agreement, we continued to seek alternative transactions that would provide greater value to us and our creditors than the transaction contemplated by the Asset Purchase Agreement.

     As a result of the formalization of the plan to sell the McClain assets and the filing of petition under the Bankruptcy Code by McClain, McClain is being accounted for as a discontinued operation.

     As part of our effort to seek alternative transactions that would provide greater value and in accordance with the bidding procedures approved by the Bankruptcy Court, we conducted an auction for the sale of McClain’s assets, however no bids were submitted for the purchase of the assets. The Bankruptcy Court entered an order approving the terms of the sale with Oklahoma Gas & Electric free and clear of all liens. The closing of the sale is subject to various closing conditions including approval by the Federal Energy Regulatory Commission. Upon consummation of the asset sale, we anticipate that all proceeds from the sale will be used to repay outstanding project debt under the secured term loan and working capital facility. On July 9, 2004, NRG McClain completed the sale of its 77% interest in the McClain Generating Station to Oklahoma Gas & Electric Company. The Oklahoma Municipal Power Authority will continue to own the remaining 23% interest in the facility. The proceeds of $160.2 million from the sale will be used to repay outstanding project debt under the secured term loan and working capital facility. A loss of $3.2 million was recognized as of June 30, 2004 based upon the final terms of the sale.

     Penobscot Energy Recovery Company (PERC) — During the first quarter of 2004, we received board authorization to proceed with the sale of our interest in PERC to SET PERC Investment LLC that reached financial closing in April 2004. Upon completion of the transaction, we received net proceeds of $18.4 million, resulting in a gain of $2.0 million, net of tax.

     Cobee — During the first quarter of 2004, we entered into an agreement for the sale of our interest in our Cobee project to Globeleq Holdings Limited, which reached financial closing in April 2004. Upon completion of the transaction, we received net proceeds of approximately $50.0 million, resulting in a gain of $2.8 million.

     LSP Energy — In May 2004 we reached an agreement to sell our 100 percent interest in an 837-megawatt generating plant in Batesville, Mississippi to Complete Energy Partners LLC. We expect to realize cash proceeds of $26.5 million, subject to certain purchase price adjustments and transaction costs. A gain of approximately $16.0 million is expected upon completion of the sale.

     Hsin Yu — During the second quarter of 2004, we entered into an agreement for the sale of our interest in our Hsin Yu project to a minority interest shareholder, Asia Pacific Energy Development Company Ltd., which reached financial closing in May 2004. Upon completion of the transaction, we received net proceeds of $1.0 million, resulting in a gain of approximately $10.3 million, resulting from our negative equity in the project. In addition, although we have no continuing involvement in the project, we retained the prospect of receiving an additional $1.0 million in additional proceeds upon final closing of Phase II of the project.

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Note 7 — Write Downs and (Gains)/Losses on Sales of Equity Method Investments

     Investments accounted for by the equity method are reviewed for impairment in accordance with APB Opinion No. 18. APB Opinion 18 requires that a loss in value of an investment that is other than a temporary decline should be recognized. Gains are recognized on completion of the sale. Write downs and (gains)/ losses on sales of equity method investments recorded in operating expenses in the consolidated statement of operations includes the following:
 	 	 	 	 	 	 	 	 	
 	 	Predecessor Company

	
 	 	Year Ended	 	For the Period	
 	 	December 31,

	 	January 1 -
December 5,	
 	 	2002

	 	2003

	
 	 	(In thousands)	
NEO Corporation — Minnesota Methane	 	$	12,292	 	 	$	12,257	 	
NEO Corporation — MM Biogas	 	 	3,251	 	 	 	2,613	 	
Kondapalli	 	 	12,751	 	 	 	(519	)	
ECKG	 	 	—	 	 	 	(2,871	)	
Loy Yang	 	 	111,383	 	 	 	146,354	 	
Mustang	 	 	—	 	 	 	(12,124	)	
Energy Development Limited (EDL)	 	 	14,220	 	 	 	—	 	
Sabine River Works	 	 	48,375	 	 	 	—	 	
Kingston	 	 	(9,876	)	 	 	—	 	
Mt. Poso	 	 	1,049	 	 	 	—	 	
Powersmith	 	 	3,441	 	 	 	—	 	
Collinsville Power Station	 	 	3,586	 	 	 	—	 	
Other	 	 	—	 	 	 	1,414	 	

 	 	 	 	

 	 	
Total write downs and (gains) losses of equity method investments	 	$	200,472	 	 	$	147,124	 	

 	 	 	 	

 	 	
Write Downs of Equity Method Investments

     NEO Corporation — Minnesota Methane — We recorded an impairment charge of $12.3 million during 2002 to write-down our 50% investment in Minnesota Methane. We recorded an additional impairment charge of $14.5 million during the first quarter of 2003. These charges were related to a revised project outlook and management’s belief that the decline in fair value was other than temporary. In May 2003, the project lenders to the wholly-owned subsidiaries of NEO Landfill Gas, Inc. and Minnesota Methane LLC foreclosed on our membership interest in the NEO Landfill Gas, Inc. subsidiaries and our equity interest in Minnesota Methane LLC. Upon completion of the foreclosure, we recorded a gain of $2.2 million. This gain resulted from the release of certain obligations.

     NEO Corporation — MM Biogas — We recorded an impairment charge of $3.2 million during 2002 to write-down our 50% investment in MM Biogas. This charge was related to revised project outlook and management’s belief that the decline in fair value was other than temporary. In November 2003, we entered into a sales agreement with Cambrian Energy Development to sell our 50% interest in MM Biogas. We recorded an additional impairment charge of $2.6 million during the fourth quarter of 2003 due to developments related to the sale that indicated an impairment of our book value that was considered to be other than temporary.

     Kondapalli — In the fourth quarter of 2002, we wrote down our investment in Kondapalli by $12.7 million due to recent estimates of sales value, which indicated an impairment of our book value that was considered to be other than temporary. On January 30, 2003, we signed a sale agreement with the Genting Group of Malaysia, or “Genting”, to sell our 30% interest in Lanco Kondapalli Power Pvt Ltd, or “Kondapalli”, and a 74% interest in Eastern Generation Services (India) Pvt Ltd (the O&M company). Kondapalli is based in Hyderabad, Andhra Pradesh, India, and is the owner of a 368 MW natural gas fired combined cycle gas turbine. In the first quarter of 2003, we wrote down our investment in Kondapalli by $1.3 million based on the final sale agreement. The sale closed on May 30, 2003 resulting in net cash proceeds of approximately $24 million and a gain of approximately $1.8 million. The gain resulted from incurring lower selling costs than estimated as part of the first quarter impairment.

     ECKG — In September 2002, we announced that we had reached agreement to sell our 44.5% interest in the ECKG power station in connection with our Csepel power generating facilities, and our interest in Entrade, an electricity trading business, to Atel, an independent energy group headquartered in Switzerland. The transaction closed in January 2003 and resulted in cash proceeds of $65.3 million and a net loss of less than $1.0 million. In accordance with the purchase agreement, we were to receive additional

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consideration if Atel purchased shares held by our partner. During the second quarter of 2003, we received approximately $3.7 million of additional consideration.

     Loy Yang — Based on a third party market valuation and bids received in response to marketing Loy Yang for possible sale, we recorded a write down of our investment of approximately $111.4 million during 2002 ($53.6 million during the third quarter and an additional $57.8 million during the fourth quarter). This write-down reflected management’s belief that the decline in fair value of the investment was other than temporary. Accumulated other comprehensive loss at December 31, 2002 included foreign currency translation losses of approximately $76.7 million related to Loy Yang.

     In May 2003, we entered into negotiations that culminated in the completion of a Share Purchase Agreement to sell 100% of the Loy Yang project. Completion of the sale is subject to various conditions. Upon completion, the sale will result in proceeds of approximately $25.0 million to $31.0 million to us; however, the final sale proceeds will vary depending on the foreign exchange rate and purchase price adjustments. Consequently, we recorded an additional impairment charge of approximately $146.4 million during 2003.

     Mustang Station — On July 7, 2003, we completed the sale of our 50% interest in Mustang Station, a gas-fired combined cycle power generating plant located in Denver City, Texas, to EIF Mustang Holdings I, LLC. The sale resulted in net cash proceeds of approximately $13.3 million and a net gain of approximately $12.1 million.

     Energy Development Limited — On July 25, 2002, we announced that we completed the sale of our ownership interests in an Australian energy company, Energy Development Limited, or “EDL.” EDL is a listed Australian energy company engaged in the development and management of an international portfolio of projects with a particular focus on renewable and waste fuels. In October 2002, we received proceeds of $78.5 million (AUS), or approximately $43.9 million (USD), in exchange for our ownership interest in EDL with the closing of the transaction. During the third quarter of 2002, we recorded a write-down of the investment of approximately $14.2 million to write down the carrying value of our equity investment due to the pending sale.

     Sabine River — In September 2002, we agreed to transfer our indirect 50% interest in SRW Cogeneration LP, or “SRW”, to our partner in SRW, Conoco, Inc. in consideration for Conoco’s agreement to terminate or assume all of our obligations, in relation to SRW. SRW owns a cogeneration facility in Orange County, Texas. We recorded a charge of approximately $48.4 million during the quarter ended September 30, 2002 to write down the carrying value of our investment due to the pending sale. The transaction closed on November 5, 2002.

     Kingston — In December 2002, we completed the sale of our 25% interest in Kingston Cogeneration LP, based near Toronto, Canada to Northland Power Income Fund. We received net proceeds of $15.0 million resulting in a gain on sale of approximately $9.9 million.

     Mt. Poso — In September 2002, we agreed to sell our 39.5% indirect partnership interest in the Mt. Poso Cogeneration Company, a California limited partnership, or “Mt. Poso”, for approximately $10 million to Red Hawk Energy, LLC. Mt. Poso owns a 49.5 MW coal-fired cogeneration power plant and thermally enhanced oil recovery facility located 20 miles north of Bakersfield, California. The sale closed in November 2002 resulting in a loss of approximately $1.0 million.

     Powersmith — During the fourth quarter of 2002, we wrote down our investment in Powersmith in the amount of approximately $3.4 million due to recent developments, which indicated impairment of our book value that is considered to be other than temporary.

     Collinsville Power Station — Based on third party market valuation and bids received in response to marketing the investment for possible sale, we recorded a write down of our investment of approximately $4.1 million during the second quarter of 2002. In August 2002, we announced that we had completed the sale of our 50% interest in the 192 MW Collinsville Power Station in Australia, to our partner, a subsidiary of Transfield Services Limited for $8.6 million (AUS), or approximately $4.8 million (USD). Our ultimate loss on the sale of Collinsville Power Station was approximately $3.6 million.

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Note 8 — Other Charges (Credits)

     Restructuring, impairment charges, legal settlement costs and fresh start adjustments included in operating expenses in the Consolidated Statement of Operations include the following:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Reorganized	
 	 	Predecessor Company

	 	NRG

	
 	 	 	 	 	 	For the Period	 	For the Period	
 	 	Year Ended	 	January 1 -	 	December 6 -	
 	 	December 31,	 	December 5,	 	December 31,	
 	 	2002

	 	2003

	 	2003

	
 	 	(In thousands)	
Impairment charges	 	$	2,638,315	 	 	$	228,896	 	 	$	—	 	
Reorganization items	 	 	—	 	 	 	197,825	 	 	 	2,461	 	
Restructuring charges	 	 	111,315	 	 	 	8,679	 	 	 	—	 	
Legal settlement	 	 	—	 	 	 	462,631	 	 	 	—	 	
Fresh Start adjustments	 	 	—	 	 	 	(3,895,541	)	 	 	—	 	

 	 	 	 	

 	 	 	 	

 	 	
Total	 	$	2,749,630	 	 	$	(2,997,510	)	 	$	2,461	 	
Less discontinued operations	 	 	186,570	(1)	 	 	223,095	(2)	 	 	—	 	

 	 	 	 	

 	 	 	 	

 	 	
Total – continuing operations	 	$	2,563,060	 	 	$	(3,220,605	)	 	$	2,461	 	

 	 	 	 	

 	 	 	 	

 	 	

(1)	 	Consists of impairment charges.	
 	 	 	
(2)	 	Consists of Fresh Start adjustments.	
     Impairment Charges

     We review the recoverability of our long-lived assets in accordance with the guidelines of SFAS No. 144. As a result of this review, we recorded impairment charges of $2.5 billion and $228.9 million for the year ended December 31, 2002 and the period from January 1, 2003 through December 5, 2003 respectively, as shown in the table below.

     To determine whether an asset was impaired, we compared asset carrying values to total future estimated undiscounted cash flows. Separate analyses were completed for assets or groups of assets at the lowest level for which identifiable cash flows were largely independent of the cash flows of other assets and liabilities. The estimates of future cash flows included only future cash flows, net of associated cash outflows, directly associated with and expected to arise as a result of our assumed use and eventual disposition of the asset. Cash flow estimates associated with assets in service were based on the asset’s existing service potential. The cash flow estimates may include probability weightings to consider possible alternative courses of action and outcomes, given the uncertainty of available information and prospective market conditions.

     If an asset was determined to be impaired based on the cash flow testing performed, an impairment loss was recorded to write down the asset to its fair value. Estimates of fair value were based on prices for similar assets and present value techniques. Fair values determined by similar asset prices reflect our current estimate of recoverability from expected marketing of project assets. For fair values determined by projected cash flows, the fair value represents a discounted cash flow amount over the remaining life of each project that reflects project-specific assumptions for long-term power pool prices, escalated future project operating costs, and expected plant operation given assumed market conditions.

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     Impairment charges (credits) included the following asset impairments (realized gains) for the year ended December 31, 2002 and for the period January 1, 2002 to December 5, 2003:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor Company

	 	 	
 	 	 	 	 	 	 	 	For the Period	 	 	
 	 	 	 	Year Ended	 	January 1 -	 	 	
 	 	 	 	December 31,	 	December 5,	 	 	
Project Name

	 	Project Status

	 	2002

	 	2003

	 	Fair Value Basis

	
 	 	(In thousands)	
Devon Power LLC	 	Operating at a loss	 	$	—	 	 	$	64,198	 	 	Projected cash flows	
Middletown Power LLC	 	Operating at a loss	 	 	—	 	 	 	157,323	 	 	Projected cash flows	
Arthur Kill Power, LLC	 	Terminated construction
project	 	 	—	 	 	 	9,049	 	 	Projected cash flows	
Langage (UK)	 	Terminated	 	 	42,333	 	 	 	(3,091	)	 	Estimated market price/Realized gain	
Turbine	 	Sold	 	 	—	 	 	 	(21,910	)	 	Realized gain	
Berrians Project	 	Terminated	 	 	—	 	 	 	14,310	 	 	Realized loss	
Termo Rio	 	Terminated	 	 	—	 	 	 	6,400	 	 	Realized loss	
Nelson	 	Terminated	 	 	467,523	 	 	 	—	 	 	Similar asset prices	
Pike	 	Terminated	 	 	402,355	 	 	 	—	 	 	Similar asset prices	
Bourbonnais	 	Terminated	 	 	264,640	 	 	 	—	 	 	Similar asset prices	
Meriden	 	Terminated	 	 	144,431	 	 	 	—	 	 	Similar asset prices	
Brazos Valley	 	Foreclosure completed in January 2003	 	 	102,900	 	 	 	—	 	 	Projected cash flows	
Kendall, Batesville & other expansion projects	 	Terminated	 	 	120,006	 	 	 	—	 	 	Projected cash flows	
Turbines & equipment	 	Equipment being
marketed	 	 	701,573	 	 	 	—	 	 	Similar asset prices	
Audrain	 	Operating at a loss	 	 	66,022	 	 	 	—	 	 	Projected cash flows	
Somerset	 	Operating at a loss	 	 	49,289	 	 	 	—	 	 	Projected cash flows	
Bayou Cove	 	Operating at a loss	 	 	126,528	 	 	 	—	 	 	Projected cash flows	
Hsin Yu	 	Operating at a loss	 	 	121,864	 	 	 	—	 	 	Projected cash flows	
Other	 	 	 	 	28,851	 	 	 	2,617	 	 	 	

 	 	 	 	

 	 	 	 	
Total impairment charges (credits)	 	 	 	 	2,638,315	 	 	 	228,896	 	 	 	
Less Discontinued Operations	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Hsin Yu	 	 	 	 	121,864	 	 	 	—	 	 	Projected cash flows	
Batesville	 	 	 	 	64,706	 	 	 	—	 	 	Projected cash flows	

 	 	 	 	

 	 	 	 	
Impairment charges	 	 	 	$	2,451,745	 	 	$	228,896	 	 	 	

 	 	 	 	

 	 	 	 	
     Credit rating downgrades, defaults under certain credit agreements, increased collateral requirements and reduced liquidity experienced during the third quarter of 2002 were “triggering events” which required us to review the recoverability of our long-lived assets. Adverse economic conditions resulted in declining energy prices. Consequently, we determined that many of our construction projects and operational projects were impaired during the third quarter of 2002 and should be written down to fair market value.

     Connecticut Facilities — As a result of regulatory developments and changing circumstances in the second quarter of 2003, we updated the facilities’ cash flow models to incorporate changes to reflect the impact of the April 25, 2003 FERC’s orders on regional and locational pricing, and to update the estimated impact of future locational capacity or deliverability requirements. Based on these revised cash flow models, management determined that the new estimates of pricing and cost recovery levels were not projected to return sufficient revenue to cover the fixed costs at Devon Power LLC and Middletown Power LLC. As a consequence, during the second quarter of 2003 we recorded $64.2 million and $157.3 million as impairment charges for Devon Power LLC and Middletown Power LLC, respectively.

     Langage (UK) — During the third quarter of 2002, we reviewed the recoverability of our Langage assets pursuant to SFAS No. 144 and recorded a charge of $42.3 million. In August 2003 we closed on the sale of Langage to Carlton Power Limited resulting in net cash proceeds of approximately $1.5 million, of which $1.0 million was received in 2003 and $0.5 million during the first quarter of 2004, and a net gain of approximately $3.1 million.

     Arthur Kill Power, LLC — During the third quarter of 2003, we cancelled our plans to re-establish fuel oil capacity at our Arthur Kill plant. This resulted in a charge of approximately $9.0 million to write-off assets under development.

     Turbines — In October 2003, we closed on the sale of three turbines and related equipment. The sale resulted in net cash proceeds of $70.7 million and a gain of approximately $21.9 million.

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     Berrians Project — During the fourth quarter of 2003, we cancelled plans to construct the Berrians peaking facility on the land adjacent to our Astoria facility. Berrians was originally scheduled to commence operations in the summer of 2005; however, based on the remaining costs to complete and the current risk profile of merchant peaking units, the construction project was terminated. This resulted in a charge of approximately $14.3 million to write off the project’s assets.

     Termo Rio — Termo Rio is a 1040 green field cogeneration project located in the state of Rio de Janeiro, Brazil. Based on the project’s failure to meet certain key milestones, we exercised our rights under the project agreements to sell our debt and equity interests in the project to our partner. We are in arbitration over the amount of compensation we are to receive for our interests in the project. Based on continued negotiations aimed at settling the case and the positions of the parties in the arbitration we recorded an impairment charge of $6.4 million to reflect our investment interest at the amount expected to be recovered through a sale. On March 8, 2003, the arbitral tribunal decided most, but not all, of the issues in our favor. The final amount of the arbitral award to NRG has not been conclusively determined and the parties may seek to modify or challenge the award. We believe we will recover the amount we have recorded on our balance sheet.

     There were no impairment charges for the period December 6, 2003 through December 31, 2003.

     Reorganization Items

     For the period from January 1, 2003 to December 5, 2003, we incurred $197.8 million in reorganization costs and for the period from December 6, 2003 to December 31, 2003 we incurred $2.5 million in reorganization costs. All reorganization costs have been incurred since we filed for bankruptcy in May 2003. The following table provides the detail of the types of costs incurred:
 	 	 	 	 	 	 	 	 	
 	 	Predecessor	 	Reorganized	
 	 	Company

	 	NRG

	
 	 	For the Period	 	For the Period	
 	 	January 1 -	 	December 6 -	
 	 	December 5,	 	December 31,	
 	 	2003

	 	2003

	
 	 	(In thousands)	
Reorganization items	 	 	 	 	 	 	 	 	
Professional fees	 	$	82,186	 	 	$	2,461	 	
Deferred financing costs	 	 	55,374	 	 	 	—	 	
Pre-payment settlement	 	 	19,609	 	 	 	—	 	
Interest earned on accumulated cash	 	 	(1,059	)	 	 	—	 	
Contingent equity obligation	 	 	41,715	 	 	 	—	 	

 	 	 	 	

 	 	
Total reorganization items	 	$	197,825	 	 	$	2,461	 	

 	 	 	 	

 	 	
     Restructuring Charges

     We incurred total restructuring charges of approximately $111.3 million for the year ended December 31, 2002. These costs consisted of employee separation costs and advisor fees. We incurred an additional $8.7 million of employee separation costs and advisor fees during 2003 until we filed for bankruptcy in May 2003. Subsequent to that date we recorded all advisor fees as reorganization costs.

     Legal Settlement

     During the third quarter of 2003, we recorded $396.0 million in connection with the resolution of the FirstEnergy Arbitration Claim. As a result of this resolution, FirstEnergy retained ownership of the Lake Plant Assets and received an allowed general unsecured claim of $396.0 million under the NRG plan of reorganization submitted to the Bankruptcy Court.

     In November 2003, we settled various litigation with Fortistar Capital in which Fortistar Capital released us from all litigation claims in exchange for a $60.0 million pre-petition claim and an $8.0 million post-petition claim. We had previously recorded $10.8 million in connection with various legal disputes with Fortistar Capital; accordingly, we recorded an additional $57.2 million during November 2003.

     In August of 1995, we entered into a Marketing, Development and Joint Proposing Agreement, “the Marketing Agreement”, with Cambrian Energy Development LLC, or “Cambrian.” Various claims had arisen in connection with this Marketing Agreement. In November 2003, we entered into a Settlement Agreement with Cambrian where we agreed to transfer our 100% interest in three gasco

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projects (NEO Ft. Smith, NEO Phoenix and NEO Woodville) and our 50% interest in two genco projects (MM Phoenix and MM Woodville) to Cambrian. In addition, we agreed to pay approximately $1.8 million in settlement of royalties incurred in connection with the Marketing Agreement. We had previously recorded a liability for royalties owed to Cambrian therefore we recorded an additional $1.4 million during November 2003.

     In November 2003, we settled our dispute with Dick Corporation in connection with Meriden Gas Turbines, which resulted in our recording an additional liability of $8.0 million in November 2003.

     Fresh Start Adjustments

     During the fourth quarter of 2003, we recorded a credit of $4.1 billion in connection with fresh start adjustments as discussed in Note 3. Following is a summary of the significant effects of the reorganization and Fresh Start:
 	 	 	 	 	
 	 	(In millions)	
Discharge of corporate level debt	 	$	5,162	 	
Discharge of other liabilities	 	 	811	 	
Establishment of creditor pool	 	 	(1,040	)	
Receivable from Xcel	 	 	640	 	
Revaluation of fixed assets	 	 	(1,392	)	
Revaluation of equity investments	 	 	(207	)	
Valuation of SO(2) emission credits	 	 	374	 	
Valuation of out of market contracts, net	 	 	(400	)	
Fair market valuation of debt	 	 	108	 	
Valuation of pension liabilities	 	 	(61	)	
Other valuation adjustments	 	 	(100	)	

 	 	
Total Fresh Start adjustments	 	 	3,895	 	
Less discontinued operations	 	 	224	 	

 	 	
Total Fresh Start adjustments – continuing operations	 	$	4,119	 	

 	 	
Note 9 — Asset Retirement Obligation

     Effective January 1, 2003, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” or “SFAS No. 143.” SFAS No. 143 requires an entity to recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred. Upon initial recognition of a liability for an asset retirement obligation, an entity shall capitalize an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes and written or oral contracts, including obligations arising under the doctrine of promissory estoppel.

     We identified certain retirement obligations within our power generation operations related to our North America projects in the South Central region, the Northeast region, Australia, our Alternative Energy projects and our Thermal projects. These asset retirement obligations are related primarily to the future dismantlement of equipment on leased property and environment obligations related to ash disposal site closures. We also identified other asset retirement obligations including plant dismantlement that could not be calculated because the assets associated with the retirement obligations were determined to have an indeterminate life. The adoption of SFAS No. 143 resulted in recording a $2.6 million increase to property, plant and equipment and a $4.2 million increase to other long-term obligations. The cumulative effect of adopting SFAS No. 143 was recorded as a $0.6 million increase to depreciation expense and a $1.6 million increase to cost of majority-owned operations in the period from January 1, 2003 to December 5, 2003 as we considered the cumulative effect to be immaterial.

     The following represents the balances of the asset retirement obligation as of January 1, 2003 and the additions and accretion of the asset retirement obligation for the periods January 1, 2003 through December 5, 2003 and the period of December 6, 2003 through December 31, 2003, which is included in other long-term obligations in the consolidated balance sheet. Prior to December 5, 2003, we completed our annual review of asset retirement obligations. As part of that review we made revisions to our previously recorded obligation in the amount of $4.0 million. The revisions included identification of new obligations as well as changes in costs or procedures required at retirement date. As a result of adopting Fresh Start we revalued our asset retirement obligations on December 6, 2003. We recorded an additional asset retirement obligation of $7.3 million in connection with fresh start reporting. This amount

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results from a change in the discount rate used between adoption and fresh starting reporting as of December 5, 2003, equal to 500 to 600 basis points.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor Company

	
 	 	Beginning	 	 	 	Accretion for	 	 	 	Ending	
 	 	Balance	 	 	 	Period Ended	 	Adjustment for	 	Balance	
 	 	January 1,	 	Revisions	 	December 5,	 	Fresh Start	 	December 5,	
Description

	 	2003

	 	to Estimate

	 	2003

	 	Reporting

	 	2003

	
 	 	(In thousands)	
South Central Region	 	$	396	 	 	$	—	 	 	$	57	 	 	$	2,170	 	 	$	2,623	 	
Northeast Region	 	 	2,045	 	 	 	4,034	 	 	 	634	 	 	 	4,978	 	 	 	11,691	 	
Australia	 	 	5,834	 	 	 	—	 	 	 	3,282	 	 	 	—	 	 	 	9,116	 	
Alternative Energy	 	 	629	 	 	 	—	 	 	 	73	 	 	 	128	 	 	 	830	 	
Thermal	 	 	1,171	 	 	 	9	 	 	 	93	 	 	 	53	 	 	 	1,326	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total asset retirement obligation	 	$	10,075	 	 	$	4,043	 	 	$	4,139	 	 	$	7,329	 	 	$	25,586	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	

 	 	Reorganized NRG

	
 	 	 	 	 	 	Accretion for	 	 	
 	 	Beginning	 	Period	 	Ending	
 	 	Balance	 	December 6 -	 	Balance	
 	 	December 6,	 	December 31,	 	December 31,	
Description

	 	2003

	 	2003

	 	2003

	
 	 	(In thousands)	
South Central Region	 	$	2,623	 	 	$	15	 	 	$	2,638	 	
Northeast Region	 	 	11,691	 	 	 	59	 	 	 	11,750	 	
Australia	 	 	9,116	 	 	 	322	 	 	 	9,438	 	
Alternative Energy	 	 	830	 	 	 	5	 	 	 	835	 	
Thermal	 	 	1,326	 	 	 	7	 	 	 	1,333	 	

 	 	 	 	

 	 	 	 	

 	 	
Total asset retirement obligation	 	$	25,586	 	 	$	408	 	 	$	25,994	 	

 	 	 	 	

 	 	 	 	

 	 	
     The following represents the pro-forma effect on our net income for the twelve months ended December 31, 2001 and 2002, as if we had adopted SFAS No. 143 as of January 1, 2001:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor Company

	
 	 	Twelve Months	 	Twelve Months	 	For the Period	
 	 	Ended	 	Ended	 	January 1 —	
 	 	December 31,	 	December 31,	 	December 5,	
 	 	2001

	 	2002

	 	2003

	
 	 	(In thousands)	
Income (loss) from continuing operations as reported	 	$	210,049	 	 	$	(2,791,200	)	 	$	2,947,262	 	
Pro-forma adjustment to reflect retroactive adoption of SFAS No. 143	 	 	(1,564	)	 	 	(677	)	 	 	2,154	 	

 	 	 	 	

 	 	 	 	

 	 	
Pro-forma income (loss) from continuing operations	 	$	208,485	 	 	$	(2,791,877	)	 	$	2,949,416	 	

 	 	 	 	

 	 	 	 	

 	 	
Net income (loss) as reported	 	$	265,204	 	 	$	(3,464,282	)	 	$	2,766,445	 	
Pro-forma adjustment to reflect retroactive adoption of SFAS No. 143	 	 	(1,564	)	 	 	(677	)	 	 	2,154	 	

 	 	 	 	

 	 	 	 	

 	 	
Pro-forma net income (loss)	 	$	263,640	 	 	$	(3,464,959	)	 	$	2,768,599	 	

 	 	 	 	

 	 	 	 	

 	 	
     On a pro forma basis an Asset Retirement obligation of $8.4 million and $10.1 million would have been recorded as an other long-term obligation as of January 1, 2002 and December 31, 2002, based on similar assumptions used to determine the amounts on our balance sheet as of December 6, 2003 and December 31, 2003.

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Note 10 — Inventory

     Inventory, which is stated at the lower of weighted average cost or market consists of:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor	 	 	
 	 	Company

	 	Reorganized NRG

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2002

	 	2003

	 	2003

	
 	 	(In thousands)	
Fuel oil	 	$	51,443	 	 	$	69,799	 	 	$	71,861	 	
Coal	 	 	82,554	 	 	 	63,641	 	 	 	59,555	 	
Natural gas	 	 	153	 	 	 	377	 	 	 	856	 	
Other fuels	 	 	2,852	 	 	 	9,874	 	 	 	10,156	 	
Spare parts	 	 	109,311	 	 	 	66,024	 	 	 	58,863	 	
Emission credits	 	 	14,742	 	 	 	4,478	 	 	 	4,478	 	
Other	 	 	6,301	 	 	 	203	 	 	 	207	 	

 	 	 	 	

 	 	 	 	

 	 	
Total inventory	 	 	267,356	 	 	 	214,396	 	 	 	205,976	 	
Less discontinued operations	 	 	13,344	 	 	 	18,160	 	 	 	11,050	 	

 	 	 	 	

 	 	 	 	

 	 	
Total inventory – continuing operations	 	$	254,012	 	 	$	196,236	 	 	$	194,926	 	

 	 	 	 	

 	 	 	 	

 	 	
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Note 11 — Notes Receivable

     Notes receivable consists primarily of fixed and variable rate notes secured by equity interests in partnerships and joint ventures. The notes receivable are as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor	 	 	
 	 	Company

	 	Reorganized NRG

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2002

	 	2003

	 	2003

	
 	 	(In thousands)	
Investment in Bonds	 	 	 	 	 	 	 	 	 	 	 	 	
Audrain County, due December 2023, 10%	 	$	239,930	 	 	$	239,930	 	 	$	239,930	 	
NRG Pike LLC Mississippi Industrial Revenue Bonds due May 2010, 7.1%	 	 	155,477	 	 	 	—	 	 	 	—	 	

 	 	 	 	

 	 	 	 	

 	 	
Investment in bonds	 	 	395,407	 	 	 	239,930	 	 	 	239,930	 	

 	 	 	 	

 	 	 	 	

 	 	
Notes Receivables	 	 	 	 	 	 	 	 	 	 	 	 	
Triton Coal Co., note due December 2003, non-interest bearing	 	 	3,000	 	 	 	1,500	 	 	 	—	 	
O’Brien Cogen II note, due 2008, non-interest bearing	 	 	627	 	 	 	686	 	 	 	692	 	
Southern Minnesota-Prairieland Solid Waste, note due 2003, 7%	 	 	12	 	 	 	—	 	 	 	—	 	
Omega Energy, LLC, due 2004, 12.5%	 	 	4,145	 	 	 	3,708	 	 	 	3,708	 	
Omega Energy, LLC, due 2009, 11%	 	 	1,533	 	 	 	1,583	 	 	 	1,583	 	
Northbrook Carolina Hydro II, LLC, due November 2005, 8.5%	 	 	—	 	 	 	86	 	 	 	84	 	
Elk River — GRE, due December 31, 2008, non-interest bearing	 	 	1,837	 	 	 	1,564	 	 	 	1,564	 	
NRG Processing Solutions	 	 	—	 	 	 	134	 	 	 	134	 	
Audrain Generating LLC	 	 	—	 	 	 	—	 	 	 	118	 	
Termo Rio (via NRGenerating Luxembourg (No. 2) S.a.r.l, due 20 years after plant becomes operational, 19.5%	 	 	63,723	 	 	 	57,323	 	 	 	57,323	 	
SET PERC Investment, LLC, due December 31, 2005, 7%	 	 	7,320	 	 	 	—	 	 	 	—	 	

 	 	 	 	

 	 	 	 	

 	 	
Notes receivables and bonds — non-affiliates	 	 	477,604	 	 	 	306,514	 	 	 	305,136	 	

 	 	 	 	

 	 	 	 	

 	 	
NEO notes to various affiliates due primarily 2012, prime +2%	 	 	9,538	 	 	 	9,419	 	 	 	9,419	 	
NRG (LSP Nelson)	 	 	—	 	 	 	—	 	 	 	200	 	
Kladno Power (No. 1) B.V	 	 	2,442	 	 	 	—	 	 	 	—	 	
Kladno Power (No. 2) B.V. notes to various affiliates, non-interest bearing	 	 	46,801	 	 	 	—	 	 	 	—	 	
Saale Energie Gmbh, indefinite maturity date, 4.75%-7.79%	 	 	86,246	 	 	 	107,391	 	 	 	111,892	 	
Northbrook Texas LLC, due February 2024, 9.25%	 	 	8,967	 	 	 	8,841	 	 	 	8,841	 	

 	 	 	 	

 	 	 	 	

 	 	
Notes receivable — affiliates	 	 	153,994	 	 	 	125,651	 	 	 	130,352	 	

 	 	 	 	

 	 	 	 	

 	 	
Reserve for Uncollectible Notes Receivable	 	 	(7,320	)	 	 	—	 	 	 	—	 	
Other	 	 	 	 	 	 	 	 	 	 	 	 	
Saale Energia GmbH, due August 31, 2021, 13.88% (direct financing lease)	 	 	366,417	 	 	 	435,045	 	 	 	451,449	 	

 	 	 	 	

 	 	 	 	

 	 	
Subtotal	 	 	990,695	 	 	 	867,210	 	 	 	886,937	 	
Less current maturities	 	 	54,711	 	 	 	66,628	 	 	 	65,341	 	

 	 	 	 	

 	 	 	 	

 	 	
Total	 	$	935,984	 	 	$	800,582	 	 	$	821,596	 	

 	 	 	 	

 	 	 	 	

 	 	
     Investment in bonds is comprised of marketable debt securities. These securities consist of municipal bonds of Audrain County, Missouri and Mississippi Industrial Revenue Bonds. The Audrain County bonds mature in 2023 and the Mississippi Industrial bonds mature in 2010. These investments in bonds are classified as held to maturity and are recorded at amortized cost. The carrying value of these bonds approximates fair value. Both the Audrain County bonds and the Mississippi Industrial Revenue Bonds are pledged as

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collateral for the related debt owed to each county. As further described in Note 17, each of these transactions have offsetting obligations.

Note 12 — Property, Plant and Equipment

     The major classes of property, plant and equipment were as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	 	 	 	 	
 	 	 	 	Company	 	Reorganized NRG	 	Average	

	 	

	 	Remaining	
 	 	Depreciable	 	December 31,	 	December 6,	 	December 31,	 	Useful	
 	 	Lives

	 	2002

	 	2003

	 	2003

	 	Life

	
 	 	(In thousands)	
Facilities and equipment	 	10-60 Years	 	$	6,258,744	 	 	$	4,125,308	 	 	$	4,141,711	 	 	 	26	 	
Land and improvements	 	 	 	 	102,624	 	 	 	101,577	 	 	 	101,577	 	 	 	 	 	
Office furnishings and equipment	 	3-15 Years	 	 	67,030	 	 	 	34,676	 	 	 	34,673	 	 	 	3	 	
Construction in progress	 	 	 	 	633,307	 	 	 	144,426	 	 	 	151,467	 	 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	 	 	
Total property, plant and equipment	 	 	 	 	7,061,705	 	 	 	4,405,987	 	 	 	4,429,428	 	 	 	 	 	
Accumulated depreciation	 	 	 	 	(596,403	)	 	 	—	 	 	 	(13,041	)	 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	 	 	
Net property, plant and equipment	 	 	 	 	6,465,302	 	 	 	4,405,987	 	 	 	4,416,387	 	 	 	 	 	
Less discontinued operations	 	 	 	 	662,102	 	 	 	397,189	 	 	 	403,551	 	 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	 	 	
Net property, plant and equipment	 	 	 	$	5,803,200	 	 	$	4,008,798	 	 	$	4,012,836	 	 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	 	 	
     Included in construction in progress at December 31, 2002 is approximately $248.9 million related to turbines associated with cancelled projects. As of December 5, 2003 and December 31, 2003, $88.6 million of turbine cost associated with cancelled projects has been reclassified to the other asset line in the accompanying balance sheet.

Note 13 — Investments Accounted for by the Equity Method

     We had investments in various international and domestic energy projects. The equity method of accounting is applied to such investments in affiliates, which include joint ventures and partnerships, because the ownership structure prevents us from exercising a controlling influence over operating and financial policies of the projects. Under this method, equity in pretax income or losses of domestic partnerships and, generally, in the net income or losses of international projects, are reflected as equity in earnings of unconsolidated affiliates.

     A summary of certain of our more significant equity-method investments, which were in operation at December 31, 2003, is as follows:
 	 	 	 	 	 	 	
 	 	 	 	Economic	
Name

	 	Geographic Area

	 	Interest

	
West Coast Power	 	 	 	 	 	 	
El Segundo Power	 	USA	 	 	50	%	
Long Beach Generating	 	USA	 	 	50	%	
Encina	 	USA	 	 	50	%	
San Diego Combustion Turbines	 	USA	 	 	50	%	
Other	 	 	 	 	 	 	
Gladstone Power Station	 	Australia	 	 	38	%	
Loy Yang Power A	 	Australia	 	 	25	%	
MIBRAG GmbH	 	Europe	 	 	50	%	
Enfield	 	Europe	 	 	25	%	
Scudder LA Power Fund I	 	Latin America	 	 	25	%	
Rocky Road Power	 	USA	 	 	50	%	
Commonwealth Atlantic	 	USA	 	 	50	%	
NRG Saguaro LLC	 	USA	 	 	50	%	
James River Cogen	 	USA	 	 	50	%	
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     Summarized financial information for investments in unconsolidated affiliates accounted for under the equity method is as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	Reorganized	
 	 	Predecessor Company

	 	NRG

	
 	 	 	 	 	 	 	 	 	 	For the Period	 	For the Period	
 	 	Year Ended December 31,	 	January 1 -	 	December 6 -	

	 	December 5,	 	December 31,	
 	 	2001

	 	2002

	 	2003

	 	2003

	
 	 	(In thousands)	
Operating revenues	 	$	3,070,078	 	 	$	2,394,256	 	 	$	2,212,280	 	 	$	268,348	 	
Costs and expenses	 	 	2,658,168	 	 	 	2,284,582	 	 	 	2,035,812	 	 	 	202,725	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Net income	 	$	411,910	 	 	$	109,674	 	 	$	176,468	 	 	$	65,623	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Current assets	 	$	1,425,175	 	 	$	1,069,239	 	 	$	783,669	 	 	$	829,525	 	
Noncurrent assets	 	 	7,009,862	 	 	 	6,853,250	 	 	 	6,452,014	 	 	 	6,541,003	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total assets	 	$	8,435,037	 	 	$	7,922,489	 	 	$	7,235,683	 	 	$	7,370,528	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Current liabilities	 	$	1,192,630	 	 	$	1,075,785	 	 	$	1,215,827	 	 	$	1,275,724	 	
Noncurrent liabilities	 	 	4,533,168	 	 	 	3,861,285	 	 	 	3,528,600	 	 	 	3,592,342	 	
Equity	 	 	2,709,239	 	 	 	2,985,419	 	 	 	2,491,256	 	 	 	2,502,462	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total liabilities and equity	 	$	8,435,037	 	 	$	7,922,489	 	 	$	7,235,683	 	 	$	7,370,528	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
NRG’s share of equity	 	$	1,050,510	 	 	$	1,171,726	 	 	$	1,079,336	 	 	$	1,051,959	 	
NRG’s share of net income	 	$	210,032	 	 	$	68,996	 	 	$	170,901	 	 	$	13,521	 	
     West Coast Power LLC Summarized Financial Information

     We have a 50% interest in one company (West Coast Power LLC) that was considered significant as of December 31, 2003, as defined by applicable SEC regulations, we account for our investment using the equity method. Upon adoption of Fresh Start we adjusted our investment in West Coast Power to fair value as of December 6, 2003. In accordance with APB Opinion 18, we have reconciled the value of our investment as of December 6, 2003 to our share of West Coast Powers partner’s equity. As a result of pushing down the impact of Fresh Start to the projects balance sheet we determined that a contract based intangible asset with a one year remaining life, consisting of the value of West Coast Power’s CDWR energy sales contract, must be established and recognized as a basis adjustment to our share of the future earnings generated by West Coast Power. This adjustment will reduce our equity earnings in the amount of approximately $10.4 million per month during 2004 until the contract expires in December 2004. Offsetting this reduction in earnings is a favorable adjustment to reflect a lower depreciation expense resulting from the corresponding reduced value of the project’s fixed assets from Fresh Start reporting. During the period December 6, 2003 through December 31, 2003 we recorded equity earnings of $9.4 million for West Coast Power after adjustments for the reversal of $2.6 million project level depreciation expense, offset by a decrease in earnings related to $8.8 million amortization of the intangible asset for the CDWR contract. The following table summarizes financial information for West Coast Power LLC, including interests owned by us and other parties for the periods shown below:

Results of Operations
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Year Ended	 	For the Period	 	For the Period	
 	 	December 31,

	 	January 1 -
December 5,	 	December 6 -
December 31,	
 	 	2001

	 	2002

	 	2003

	 	2003

	
 	 	(In millions)	
Operating revenues	 	$	1,562	 	 	$	585	 	 	$	643	 	 	$	53	 	
Operating income	 	 	345	 	 	 	48	 	 	 	201	 	 	 	31	 	
Net income (pre-tax)	 	 	326	 	 	 	34	 	 	 	202	 	 	 	31	 	
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Financial Position
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2002

	 	2003

	 	2003

	
 	 	(In millions)	
Current assets	 	$	255	 	 	$	247	 	 	$	257	 	
Other assets	 	 	532	 	 	 	454	 	 	 	454	 	

 	 	 	 	

 	 	 	 	

 	 	
Total assets	 	$	787	 	 	$	701	 	 	$	711	 	

 	 	 	 	

 	 	 	 	

 	 	
Current liabilities	 	$	112	 	 	$	58	 	 	$	55	 	
Other liabilities	 	 	34	 	 	 	1	 	 	 	8	 	
Equity	 	 	641	 	 	 	642	 	 	 	648	 	

 	 	 	 	

 	 	 	 	

 	 	
Total liabilities and equity	 	$	787	 	 	$	701	 	 	$	711	 	

 	 	 	 	

 	 	 	 	

 	 	
Note 14 — Decommissioning Funds

     We are required by the State of Louisiana Department of Environmental Quality, or “DEQ”, to rehabilitate our Big Cajun II ash and wastewater impoundment areas, subsequent to the Big Cajun II facilities’ removal from service. On July 1, 1989, a guarantor trust fund, or “the Solid Waste Disposal Trust Fund”, was established to accumulate the estimated funds necessary for such purpose. Approximately $1.1 million was initially deposited in the Solid Waste Disposal Trust Fund in 1989, and $116,000 has been funded annually thereafter, based upon an estimated future rehabilitation cost (in 1989 dollars) of approximately $3.5 million and the remaining estimated useful life of the Big Cajun II facilities. At December 31, 2002, December 6, 2003 and December 31, 2003, the carrying value of the trust fund investments was approximately $4.6 million, $4.8 million and $4.8 million, respectively. The trust fund investments are comprised of various debt securities of the United States and are carried at amortized cost, which approximates their fair value. The amounts required to be deposited in this trust fund are separate from our calculation of the asset retirement obligation recorded for the Big Cajun II ash and wastewater impoundment areas discussed in Note No. 9.

Note 15 — Goodwill and Other Intangible Assets

     During the first quarter of 2002, we adopted SFAS No. 142 — “Goodwill and Other Intangible Assets” or “SFAS No. 142”, which requires new accounting for intangible assets, including goodwill. Intangible assets with finite lives will be amortized over their economic useful lives and periodically reviewed for impairment. Goodwill will no longer be amortized, but will be tested for impairment annually and on an interim basis if an event occurs or a circumstance changes between annual tests that may reduce the fair value of a reporting unit below its carrying value. Upon the adoption of Fresh Start, we re-evaluated the recoverability of our goodwill and intangibles. As a result, we have written off all goodwill amounts as of December 5, 2003. We have also established certain other contract based intangibles, which will be amortized over their respective contractual lives.

     Predecessor Company

     We had intangible assets with a net carrying value of $75.1 million at December 31, 2002. The Aggregate amortization expense recognized for the years ended December 31, 2002 and 2001 was approximately $2.7 million and $4.1 million, respectively. The amortization expense for the period January 1, 2003 through December 5, 2003 was $3.8 million.

     Reorganized NRG

     We had intangible assets with a net carrying value of $484.7 million and $432.4 million at December 6, 2003 and December 31, 2003. The power purchase agreements will be amortized as a reduction to revenue over the terms and conditions of each contract. The weighted average amortization period is 7 years for the power purchase agreements. Emission allowances will be amortized as additional fuel expense based upon the actual level of emissions from the respective plant through 2023. The amortization expense for the period December 6, 2003 through December 31, 2003 was $5.2 million related to power purchase agreements. The annual aggregate amortization expense for each of the five succeeding years is expected to approximate $57.2 million in year one, $37.2 million in year two, $30.0 million in years three and four, and $23.1 million in year five for both the power purchase agreements and emission allowances. Intangible assets consisted of the following:

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 	 	Predecessor Company

	 	Reorganized NRG

	
 	 	At December 31, 2002

	 	At December 6, 2003

	 	At December 31, 2003

	
 	 	Gross	 	 	 	 	 	Gross	 	 	 	 	 	Gross	 	 	
 	 	Carrying	 	Accumulated	 	Carrying	 	Accumulated	 	Carrying	 	Accumulated	
Description

	 	Amount

	 	Amortization

	 	Amount

	 	Amortization

	 	Amount

	 	Amortization

	
 	 	(In thousands)	
Goodwill*	 	$	32,958	 	 	$	6,123	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Intangibles:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Service contracts*	 	 	65,791	 	 	 	15,987	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Less discontinued operations	 	 	2,000

	 	 	 	492

	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	63,791	 	 	 	15,495	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Power purchase agreements	 	 	 	 	 	 	 	 	 	 	113,209	 	 	 	—	 	 	 	66,114	 	 	 	5,230	 	
Less discontinued operations	 	 	—

	 	 	 	—

	 	 	 	2,059

	 	 	 	—

	 	 	 	2,059

	 	 	 	18

	 	
 	 	 	 	 	 	 	 	 	 	 	111,150	 	 	 	 	 	 	 	64,055	 	 	 	5,212	 	
Emission allowances**	 	 	—	 	 	 	—	 	 	 	373,518	 	 	 	—	 	 	 	373,518	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Total intangibles	 	$	63,791	 	 	$	15,495	 	 	$	484,668	 	 	$	—	 	 	$	437,573	 	 	$	5,212	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	

*	 	Written off as part of Fresh Start since service contracts determined to be at current market rates.	
 	 	 	
**	 	No amortization recorded in 2003 as this balance includes only emission allowances for 2004 and beyond. All emission allowances for 2003 were used prior to December 5, 2003.	
     The following table summarizes the pro forma impact of implementing SFAS No. 142 at January 1, 2001 on net income (loss) for the periods presented.
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor Company

	
 	 	 	 	 	 	 	 	 	 	For the Period	
 	 	Year Ended December 31,	 	January 1 -	

	 	December 5,	
 	 	2001

	 	2002

	 	2003

	
 	 	(In thousands)	
Reported income/(loss) from continuing operations	 	$	210,049	 	 	$	(2,791,200	)	 	$	2,947,262	 	
Add back: Goodwill amortization (after-tax)	 	 	923	 	 	 	—	 	 	 	—	 	
Less discontinued operations	 	 	(95	)	 	 	—	 	 	 	—	 	

 	 	 	 	

 	 	 	 	

 	 	
Adjusted income/(loss) from continuing operations	 	$	210,877	 	 	$	(2,791,200	)	 	$	2,947,262	 	

 	 	 	 	

 	 	 	 	

 	 	
Reported net income/(loss)	 	$	265,204	 	 	$	(3,464,282	)	 	$	2,766,445	 	
Add back: Goodwill amortization (after-tax)	 	 	2,919	 	 	 	—	 	 	 	—	 	

 	 	 	 	

 	 	 	 	

 	 	
Adjusted net income/(loss)	 	$	268,123	 	 	$	(3,464,282	)	 	$	2,766,445	 	

 	 	 	 	

 	 	 	 	

 	 	
Note 16 — Accounting for Derivative Instruments and Hedging Activities

     We have adopted Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities”  or “SFAS No. 133”, as amended by SFAS No. 137, SFAS No. 138 and SFAS No. 149. SFAS No. 133 requires us to record all derivatives on the balance sheet at fair value. Changes in the fair value of non-hedge derivatives will be immediately recognized in earnings. The criteria used to determine if hedge accounting treatment is appropriate are a) the designation of the hedge to an underlying exposure, b) whether or not the overall risk is being reduced and c) if there is a high degree of correlation between the value of the derivative instrument and the underlying obligation. Formal documentation of the hedging relationship, the nature of the underlying risk, the risk management objective, and the means by which effectiveness will be assessed is created at the inception of the hedge. Changes in fair values of derivatives accounted for as hedges will either be recognized in earnings as offsets to the changes in fair value of related hedged assets, liabilities and firm commitments or, for forecasted transactions, deferred and recorded as a component of other accumulated comprehensive income, or “OCI”, until the hedged transactions occur and are recognized in earnings. The ineffective portion of a hedging derivative instrument’s change in fair value will be immediately recognized in earnings. We also formally assess both at inception and at least quarterly thereafter, whether the derivatives that are used in hedging transactions are highly effective in offsetting the changes in either the fair value or cash flows of the hedged item. This assessment includes all components of each derivative’s gain or loss unless otherwise noted. When it is determined that a derivative ceases to be a highly effective hedge, hedge accounting is discontinued.

     SFAS No. 133 applies to our long-term power sales contracts, long-term gas purchase contracts and other energy related commodities financial instruments used to mitigate variability in earnings due to fluctuations in spot market prices, hedge fuel requirements at generation facilities and protect investments in fuel inventories. SFAS No. 133 also applies to various interest rate swaps used to mitigate the risks associated with movements in interest rates and foreign exchange contracts to reduce the effect of

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fluctuating foreign currencies on foreign denominated investments and other transactions. At December 31, 2003, we had commodity contracts extending through December 2020.

     Derivative Financial Instruments

     Foreign Currency Exchange Rates

     As of December 6, 2003 and December 31, 2003, neither we nor our consolidating subsidiaries had any outstanding foreign currency exchange contracts. At December 31, 2002, we had various foreign currency exchange instruments with combined notional amounts of $3.0 million. These foreign currency exchange instruments were hedges of expected future cash flows. If the hedges had been terminated at December 31, 2002, we would have owed the counter-parties $0.3 million.

     Interest Rates

     At December 31, 2002, December 6, 2003 and December 31, 2003, our consolidating subsidiaries had various interest-rate swap agreements with combined notional amounts of $1.7 billion, $617.4 million and $620.5 million, respectively. These contracts are used to manage our exposure to changes in interest rates. If these swaps had been terminated at December 31, 2002, December 6, 2003 and December 31, 2003, we would have owed the counter-parties $41.0 million, $53.6 million and $50.2 million, respectively.

     Energy Related Commodities

     At December 31, 2002, December 6, 2003 and December 31, 2003, we had various energy related commodities financial instruments with combined notional amounts of $241.8 million, $519.7 million and $521.1 million, respectively. These financial instruments take the form of fixed price, floating price or indexed sales or purchases, options, such as puts or calls, basis transactions and swaps. These contracts are used to manage our exposure to commodity price variability in electricity, emission allowances and natural gas, oil and coal used to meet fuel requirements. If these contracts were terminated at December 31, 2002, December 6, 2003 and December 31, 2003, we would have received $58.5 million, $46.3 million and $46.0 million, from counter-parties, respectively. As of December 31, 2003, we had various long-term power sales contracts with combined notional amounts of approximately $3.2 billion.

     Credit Risk

     We have an established credit policy in place to minimize our overall credit risk. Important elements of this policy include ongoing financial reviews of all counter-parties, established credit limits, as well as monitoring, managing and mitigating credit exposure.

     Accumulated Other Comprehensive Income

     The following table summarizes the effects of SFAS No. 133 on our other comprehensive income balance as of December 31, 2003:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG

	
 	 	Energy	 	Interest	 	Foreign	 	 	
 	 	Commodities

	 	Rate

	 	Currency

	 	Total

	
 	 	(Gains/(Losses) in thousands)	
Accum. OCI balance at December 6, 2003	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	
Unwound from OCI during period:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
— due to unwinding of previously deferred amounts	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Mark to market of hedge contracts	 	 	(1,953	)	 	 	1,600	 	 	 	(170	)	 	 	(523	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Accum. OCI balance at December 31, 2003	 	$	(1,953	)	 	$	1,600	 	 	$	(170	)	 	$	(523	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Gains/(Losses) expected to unwind from OCI during next 12 months	 	$	1,323	 	 	$	745	 	 	$	—	 	 	$	2,068	 	
     During the period ended December 31, 2003, we recorded a loss in OCI of approximately $0.5 million related to changes in the fair values of derivatives accounted for as hedges. The net balance in OCI relating to SFAS No. 133 as of December 31, 2003 was an unrecognized loss of approximately $0.5 million. We expect $2.1 million of deferred net gains on derivative instruments accumulated in OCI to be recognized in earnings during the next twelve months.

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     The following table summarizes the effects of SFAS No. 133 on our other comprehensive income balance as of December 6, 2003:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor Company

	
 	 	Energy	 	Interest	 	Foreign	 	 	
 	 	Commodities

	 	Rate

	 	Currency

	 	Total

	
 	 	(Gains/(Losses) in thousands)	
Accum. OCI balance at January 1, 2003	 	$	129,496	 	 	$	(102,957	)	 	$	(261	)	 	$	26,278	 	
Unwound from OCI during period:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
— due to forecasted transactions probable of no longer occurring	 	 	—	 	 	 	32,025	 	 	 	—	 	 	 	32,025	 	
— due to unwinding of previously deferred amounts	 	 	(112,501	)	 	 	(2,280	)	 	 	—	 	 	 	(114,781	)	
Mark to market of hedge contracts	 	 	43,979	 	 	 	7,358	 	 	 	56	 	 	 	51,393	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Accum. OCI balance at December 5, 2003	 	 	60,974	 	 	 	(65,854	)	 	 	(205	)	 	 	(5,085	)	
— due to Fresh Start reporting write-off	 	 	(60,974	)	 	 	65,854	 	 	 	205	 	 	 	5,085	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Accum. OCI balance at December 6, 2003	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
     During the period ended December 5, 2003, we reclassified losses of $32.0 million from OCI to current-period earnings as a result of the discontinuance of cash flow hedges because it is probable that the original forecasted transactions will not occur by the end of the originally specified time period. Additionally, gains of $114.8 million were reclassified from OCI to current period earnings during the period ended December 5, 2003 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 period ended December 5, 2003, we recorded a gain in OCI of approximately $51.4 million related to changes in the fair values of derivatives accounted for as hedges. Our plan of reorganization became effective December 5, 2003 and, accordingly, we made adjustments for Fresh Start in accordance with SOP 90-7. These Fresh Start adjustments resulted in a write-off of net losses recorded in OCI of $5.1 million.

     The following table summarizes the effects of SFAS No. 133 on our other comprehensive income balance as of December 31, 2002:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor Company

	
 	 	Energy	 	Interest	 	Foreign	 	 	
 	 	Commodities

	 	Rate

	 	Currency

	 	Total

	
 	 	(Gains/(Losses) in thousands)	
Accum. OCI balance at December 31, 2001	 	$	142,919	 	 	$	(69,455	)	 	$	(2,363	)	 	$	71,101	 	
Unwound from OCI during period:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
— due to forecasted transactions probable of no longer occurring	 	 	—	 	 	 	(23,263	)	 	 	—	 	 	 	(23,263	)	
— due to termination of hedged items by counterparty	 	 	(6,130	)	 	 	—	 	 	 	—	 	 	 	(6,130	)	
— due to unwinding of previously deferred amounts	 	 	(77,576	)	 	 	22,337	 	 	 	2,075	 	 	 	(53,164	)	
Mark to market of hedge contracts	 	 	70,283	 	 	 	(32,576	)	 	 	27	 	 	 	37,734	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Accum. OCI balance at December 31, 2002	 	$	129,496	 	 	$	(102,957	)	 	$	(261	)	 	$	26,278	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
     During the year ended December 31, 2002, we reclassified gains of $23.3 million from OCI to current-period earnings as a result of the discontinuance of cash flow hedges because it is probable that the original forecasted transactions will not occur by the end of the originally specified time period. Also, gains of $6.1 million were reclassified from OCI to current period earnings due to the hedge items being terminated by the counterparties. Additionally, gains of $53.2 million were reclassified from OCI to current period earnings during the year ended December 31, 2002 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 year ended December 31, 2002, we recorded a gain in OCI of approximately $37.7 million related to changes in the fair values of derivatives accounted for as hedges. The net balance in OCI relating to SFAS No. 133 as of December 31, 2002 was an unrecognized gain of approximately $26.3 million.

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     Statement of Operations

     The following tables summarize the effects of SFAS No. 133 on our statement of operations for the period from December 6, 2003 through December 31, 2003:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG

	
 	 	Energy	 	Interest	 	Foreign	 	 	
 	 	Commodities

	 	Rate

	 	Currency

	 	Total

	
 	 	(Gains/(Losses) in thousands)	
Revenue from majority owned subsidiaries	 	$	(627	)	 	$	—	 	 	$	—	 	 	$	(627	)	
Cost of operations	 	 	508	 	 	 	—	 	 	 	—	 	 	 	508	 	
Other income	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Equity in earnings of unconsolidated subsidiaries	 	 	(630	)	 	 	—	 	 	 	—	 	 	 	(630	)	
Interest expense	 	 	—	 	 	 	1,983	 	 	 	—	 	 	 	1,983	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total Statement of Operations impact before tax	 	$	(749	)	 	$	1,983	 	 	$	—	 	 	$	1,234	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
     The following tables summarize the effects of SFAS No. 133 on our statement of operations for the period from January 1, 2003 through December 5, 2003:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor Company

	
 	 	Energy	 	Interest	 	Foreign	 	 	
 	 	Commodities

	 	Rate

	 	Currency

	 	Total

	
 	 	(Gains/(Losses) in thousands)	
Revenue from majority owned subsidiaries	 	$	30,027	 	 	$	—	 	 	$	—	 	 	$	30,027	 	
Cost of operations	 	 	4,607	 	 	 	—	 	 	 	—	 	 	 	4,607	 	
Other income	 	 	—	 	 	 	—	 	 	 	92	 	 	 	92	 	
Equity in earnings of unconsolidated subsidiaries	 	 	19,022	 	 	 	—	 	 	 	—	 	 	 	19,022	 	
Interest expense	 	 	—	 	 	 	(15,104	)	 	 	—	 	 	 	(15,104	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total Statement of Operations impact before tax	 	$	53,656	 	 	$	(15,104	)	 	$	92	 	 	$	38,644	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
     The following tables summarize the effects of SFAS No. 133 on our statement of operations for the period ended December 31, 2002:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor Company

	
 	 	Energy	 	Interest	 	Foreign	 	 	
 	 	Commodities

	 	Rate

	 	Currency

	 	Total

	
 	 	(Gains/(Losses) in thousands)	
Revenue from majority owned subsidiaries	 	$	9,085	 	 	$	—	 	 	$	—	 	 	$	9,085	 	
Cost of operations	 	 	9,530	 	 	 	—	 	 	 	—	 	 	 	9,530	 	
Equity in earnings of unconsolidated subsidiaries	 	 	1,426	 	 	 	970	 	 	 	—	 	 	 	2,396	 	
Other income	 	 	—	 	 	 	—	 	 	 	344	 	 	 	344	 	
Interest expense	 	 	—	 	 	 	(32,953	)	 	 	—	 	 	 	(32,953	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total Statement of Operations impact before tax	 	$	20,041	 	 	$	(31,983	)	 	$	344	 	 	$	(11,598	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
     The following tables summarize the effects of SFAS No. 133 on our statement of operations for the period ended December 31, 2001:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor Company

	
 	 	Energy	 	Foreign	 	 	
 	 	Commodities

	 	Currency

	 	Total

	
 	 	(Gains/(Losses) in thousands)	
Revenue from majority owned subsidiaries	 	$	(8,138	)	 	$	—	 	 	$	(8,138	)	
Cost of operations	 	 	17,556	 	 	 	—	 	 	 	17,556	 	
Equity in earnings of unconsolidated subsidiaries	 	 	4,662	 	 	 	—	 	 	 	4,662	 	
Other income	 	 	—	 	 	 	252	 	 	 	252	 	

 	 	 	 	

 	 	 	 	

 	 	
Total Statement of Operations impact before tax	 	$	14,080	 	 	$	252	 	 	$	14,332	 	

 	 	 	 	

 	 	 	 	

 	 	
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     Energy Related Commodities

     We are exposed to commodity price variability in electricity, emission allowances and natural gas, oil and coal used to meet fuel requirements. In order to manage these commodity price risks, we enter into financial instruments, which may take the form of fixed price, floating price or indexed sales or purchases, and options, such as puts, calls, basis transactions and swaps. Certain of these transactions have been designated as cash flow hedges. We have accounted for these derivatives by recording the effective portion of the cumulative gain or loss on the derivative instrument as a component of OCI in shareholders’ equity. We recognize deferred gains and losses into earnings in the same period or periods during which the hedged transaction affects earnings. Such reclassifications are included on the same line of the statement of operations in which the hedged item is recorded.

     No ineffectiveness was recognized on commodity cash flow hedges during the years ended December 31, 2001, December 31, 2002 or during the periods January 1, 2003 through December 5, 2003 and December 6, 2003 through December 31, 2003.

     Our pre-tax earnings for the years ended December 31, 2001, December 31, 2002, the period January 1, 2003 through December 5, 2003 and the period December 6, 2003 through December 31, 2003, were affected by an unrealized gain of $14.1 million, an unrealized gain of $20.0 million, an unrealized gain of $53.7 million and an unrealized loss of $0.7 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.

     During the year ended December 31, 2002, we reclassified gains of $83.7 million from OCI to current-period earnings. During the periods January 1, 2003 through December 5, 2003 and December 6, 2003 through December 31, 2003 gains of $112.5 and $0 million, respectively, were reclassified from OCI to current-period earnings. Our plan of reorganization became effective December 5, 2003 and, accordingly, we made adjustments for Fresh Start in accordance with SOP 90-7. These Fresh Start adjustments resulted in a write-off of net gains recorded in OCI of $61.0 million on energy related derivative instruments accounted for as hedges. We expect to reclassify an additional $1.3 million of deferred gains to earnings during the next twelve months on energy related derivative instruments accounted for as hedges.

     Interest Rates

     To manage interest rate risk, we have entered into interest-rate swaps that effectively fix the interest payments of certain floating rate debt instruments. Interest-rate swap agreements are accounted for as cash flow hedges. The effective portion of the cumulative gain or loss on the derivative instrument is reported as a component of OCI in shareholders’ equity and recognized into earnings as the underlying interest expense is incurred. Such reclassifications are included on the same line of the statement of operations in which the hedged item is recorded.

     No ineffectiveness was recognized on interest rate cash flow hedges during the years ended December 31, 2001 and December 31, 2002 or during the periods January 1, 2003 through December 5, 2003 and December 6, 2003 through December 31, 2003.

     Our pre-tax earnings for the years ended December 31, 2001 and 2002 were increased by an unrealized loss of $0 and $32.0 million, respectively, associated with changes in the fair value of interest rate derivative instruments not accounted for as hedges in accordance with SFAS No. 133.

     Our pre-tax earnings for the period January 1, 2003 through December 5, 2003 and the period December 6, 2003 through December 31, 2003, were affected by an unrealized loss of $15.1 million and an unrealized gain of $2.0 million, respectively, associated with changes in the fair value of interest rate derivative instruments not accounted for as hedges in accordance with SFAS No. 133.

     During the year ended December 31, 2002, we reclassified gains of $0.9 million from OCI to current-period earnings. During the periods January 1, 2003 through December 5, 2003 and December 6, 2003 through December 31, 2003 losses of $29.7 and $0 million, respectively, were reclassified from OCI to current-period earnings. Our plan of reorganization became effective December 5, 2003 and, accordingly, we made adjustments for Fresh Start in accordance with SOP 90-7. These Fresh Start adjustments resulted in a write-off of net losses recorded in OCI of $65.9 million on interest rate swaps accounted for as hedges. We expect to reclassify an additional $0.7 million of deferred gains to earnings during the next twelve months on interest rate swaps accounted for as hedges.

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     Foreign Currency Exchange Rates

     To preserve the U.S. dollar value of projected foreign currency cash flows, we may hedge, or protect those cash flows if appropriate foreign hedging instruments are available.

     No ineffectiveness was recognized on foreign currency cash flow hedges during the years ended December 31, 2001, December 31, 2002 or during the periods January 1, 2003 through December 5, 2003 and December 6, 2003 through December 31, 2003.

     Our pre-tax earnings for the years ended December 31, 2001 and 2002 were increased by an unrealized gain of $0.3 million and $0.3 million, respectively, associated with foreign currency hedging instruments not accounted for as hedges in accordance with SFAS No. 133.

     Our pre-tax earnings for the period January 1, 2003 through December 5, 2003 and the period December 6, 2003 through December 31, 2003, were increased by an unrealized gain of $0.1 million and $0, respectively, associated with foreign currency hedging instruments not accounted for as hedges in accordance with SFAS No. 133.

     During the year ended December 31, 2002, we reclassified losses of $2.1 million from OCI to current period earnings. During the periods January 1, 2003 through December 5, 2003 and December 6, 2003 through December 31, 2003 losses of $0 and $0 million, respectively, were reclassified from OCI to current- period earnings. Our plan of reorganization became effective December 5, 2003 and, accordingly, we made adjustments for Fresh Start in accordance with SOP 90-7. These Fresh Start adjustments resulted in a write-off of net losses recorded in OCI of $0.2 million on foreign currency swaps accounted for as hedges. We do not expect to reclassify any deferred gains or losses to earnings during the next twelve months on foreign currency swaps accounted for as hedges.

Note 17 — Debt and Capital Leases

     Long-term debt and capital leases consist of the following:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor Company

	 	Reorganized NRG

	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Fair Value	 	 	 	 	 	Fair Value	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	Principal

	 	Adjustment

	 	Principal

	 	Adjustment

	
 	 	 	 	 	 	 	 	 	 	Principal

	 	December 6,

	 	December 31,

	
 	 	Stated	 	Effective	 	December 31,	 	 	 	 	 	 	 	 	
 	 	Rate

	 	Rate

	 	2002

	 	2003

	 	2003

	 	2003

	 	2003

	
 	 	(Percent)	 	 	 	 	 	(In thousands)	 	 	 	 	 	 	 	 	
NRG Recourse Debt:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
NRG New Credit Facility, due June 23, 2010	 	 	(2	)	 	 	—	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	1,200,000	 	 	$	—	 	
NRG Energy Promissory Note, Xcel Energy, due June 5, 2006	 	 	3.00	 	 	 	9.00	 	 	 	—	 	 	 	10,000	 	 	 	(1,349	)	 	 	10,000	 	 	 	(1,310	)	
NRG Energy ROARS, due March 15, 2020	 	 	7.97	 	 	 	—	 	 	 	257,552	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
NRG Energy senior debentures (corporate units), due May 16, 2006	 	 	6.50	 	 	 	—	 	 	 	285,728	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
NRG Energy senior notes:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
December 15, 2013	 	 	8.00	 	 	 	—	 	 	 	—	 	 	 	 	 	 	 	 	 	 	 	1,250,000	 	 	 	 	 	
February 1, 2006	 	 	7.625	 	 	 	—	 	 	 	125,000	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
July 15, 2006	 	 	6.75	 	 	 	—	 	 	 	340,000	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
June 15, 2007	 	 	7.50	 	 	 	—	 	 	 	250,000	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
June 1, 2009	 	 	7.50	 	 	 	—	 	 	 	300,000	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
September 15, 2010	 	 	8.25	 	 	 	—	 	 	 	350,000	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
April 1, 2011	 	 	7.75	 	 	 	—	 	 	 	350,000	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
November 1, 2003	 	 	8.00	 	 	 	—	 	 	 	240,000	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
April 1, 2031	 	 	8.625	 	 	 	—	 	 	 	340,000	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
April 1, 2031	 	 	8.625	 	 	 	—	 	 	 	160,000	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
NRG Project — Level, Non — Recourse Debt:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
NRG Finance Company I LLC — construction revolver, May 2006	 	 	(2	)	 	 	—	 	 	 	1,081,000	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
NRG Processing Solutions, capital lease, due November 2004	 	 	9.00	 	 	 	A+ 2	(3)	 	 	676	 	 	 	355	 	 	 	12	 	 	 	326	 	 	 	10	 	
NRG Pike Energy LLC, due 2010	 	 	 	 	 	 	—	 	 	 	155,477	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
NRG Energy Center San Diego, LLC promissory note, due June 2003	 	 	8.00	 	 	 	—	 	 	 	278	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
NRG Energy Center Pittsburgh LLC, due November 2004	 	 	10.61	 	 	 	A+ 2	(3)	 	 	3,050	 	 	 	1,550	 	 	 	74	 	 	 	1,550	 	 	 	66	 	
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 	 	Predecessor Company

	 	Reorganized NRG

	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Fair Value	 	 	 	 	 	Fair Value	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	Principal

	 	Adjustment

	 	Principal

	 	Adjustment

	
 	 	 	 	 	 	 	 	 	 	Principal

	 	December 6,

	 	December 31,

	
 	 	Stated	 	Effective	 	December 31,	 	 	 	 	 	 	 	 	
 	 	Rate

	 	Rate

	 	2002

	 	2003

	 	2003

	 	2003

	 	2003

	
 	 	(Percent)	 	 	 	 	 	(In thousands)	 	 	 	 	 	 	 	 	
NRG Energy Center San Francisco LLC, senior secured notes, due November 2004	 	 	10.61	 	 	 	A+ 2	(3) 	 	 	2,310	 	 	 	860	 	 	 	45	 	 	 	860	 	 	 	41	 	
Meriden due May 14, 2003	 	 	10.00	 	 	 	—	 	 	 	—	 	 	 	500	 	 	 	—	 	 	 	500	 	 	 	—	 	
LSP Kendall Energy LLC, due September 2005(1)(5)	 	 	2.65	 	 	 	A+3.5	(4) 	 	 	495,754	 	 	 	489,198	 	 	 	(31,160	)	 	 	487,013	 	 	 	(30,370	)	
MidAtlantic Generating LLC, due October 2005(5)	 	 	4.625	 	 	 	—	 	 	 	409,201	 	 	 	406,560	 	 	 	—	 	 	 	—	 	 	 	—	 	
Camas Power Boiler LP, unsecured term loan, due June 30, 2007	 	 	3.65	 	 	 	A+ 2	(3) 	 	 	10,896	 	 	 	9,202	 	 	 	(286	)	 	 	8,628	 	 	 	(277	)	
COBEE, due July 2007(6)	 	 	(2	)	 	 	15.00	 	 	 	42,150	 	 	 	31,800	 	 	 	(3,028	)	 	 	31,800	 	 	 	(2,815	)	
Camas Power Boiler LP, revenue bonds, due August 1, 2007	 	 	3.38	 	 	 	A+ 2	(3) 	 	 	6,965	 	 	 	5,765	 	 	 	(115	)	 	 	5,765	 	 	 	(108	)	
NRG Brazos Valley LLC, due June 30, 2008	 	 	6.75	 	 	 	—	 	 	 	194,362	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Flinders Power Finance Pty, due September 2012, 6.14%-6.49%	 	 	(2	)	 	 	6.00	 	 	 	99,175	 	 	 	185,825	 	 	 	10,434	 	 	 	187,668	 	 	 	10,632	 	
Hsin Yu(6)	 	 	(2	)	 	 	—	 	 	 	85,607	 	 	 	84,980	 	 	 	(45,000	)	 	 	85,300	 	 	 	(44,480	)	
NRG Energy Center Minneapolis LLC senior secured notes due 2013 and 2017, 7.12%-7.31%	 	 	(2	)	 	 	A+ 2	(3) 	 	 	133,099	 	 	 	127,275	 	 	 	7,112	 	 	 	126,279	 	 	 	7,030	 	
LSP Energy LLC (Batesville), due 2014 and 2025, 7.16%-8.16%(6)	 	 	(2	)	 	 	8.23-9.31	 	 	 	314,300	 	 	 	307,175	 	 	 	(12,528	)	 	 	307,175	 	 	 	(12,292	)	
PERC, due 2017 and 2018(6)	 	 	6.75	 	 	 	A+ 2	(3) 	 	 	28,695	 	 	 	26,265	 	 	 	(1,228	)	 	 	26,265	 	 	 	(1,203	)	
Northbrook New York	 	 	4.10	 	 	 	4.42	 	 	 	—	 	 	 	17,223	 	 	 	(319	)	 	 	17,199	 	 	 	(315	)	
Northbrook Carolina	 	 	5.10	 	 	 	6.42	 	 	 	—	 	 	 	2,500	 	 	 	(178	)	 	 	2,475	 	 	 	(177	)	
Northbrook STS HydroPower	 	 	9.13	 	 	 	9.70	 	 	 	—	 	 	 	24,374	 	 	 	(927	)	 	 	24,506	 	 	 	(930	)	
Saale Energie GmbH, Schkopau Capital lease, due 2021	 	 	(2	)	 	 	—	 	 	 	325,583	 	 	 	318,025	 	 	 	—	 	 	 	342,469	 	 	 	—	 	
Audrain County, MO — Capital lease, due December 2023	 	 	10.00	 	 	 	—	 	 	 	239,930	 	 	 	239,930	 	 	 	—	 	 	 	239,930	 	 	 	—	 	
NRG South Central Generating LLC senior bonds, due various dates through September 15, 2024(5)	 	 	(2	)	 	 	—	 	 	 	750,750	 	 	 	750,750	 	 	 	—	 	 	 	—	 	 	 	—	 	
NRG Northeast Generating LLC senior bonds, due various dates through December 15, 2024(5)	 	 	(2	)	 	 	—	 	 	 	556,500	 	 	 	556,500	 	 	 	—	 	 	 	—	 	 	 	—	 	
NRG Peaker Finance Co. LLC (1)(5)	 	 	 	 	 	 	A+3.5	(4) 	 	 	319,362	 	 	 	319,362	 	 	 	(72,657	)	 	 	311,373	 	 	 	(72,105	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Subtotal	 	 	 	 	 	 	 	 	 	 	8,253,400	 	 	 	3,915,974	 	 	 	(151,098	)	 	 	4,667,081	 	 	 	(148,603	)	
Less discontinued operations	 	 	 	 	 	 	 	 	 	 	470,752	 	 	 	450,220	 	 	 	(61,784	)	 	 	450,540	 	 	 	(61,073	)	
Less current maturities	 	 	 	 	 	 	 	 	 	 	7,001,134	 	 	 	2,598,288	 	 	 	(101,534	)	 	 	901,242	 	 	 	(100,013	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total	 	 	 	 	 	 	 	 	 	$	781,514	 	 	$	867,466	 	 	$	12,220	 	 	$	3,315,299	 	 	$	12,483	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	

(1)	 	We have reclassified the long-term portions of these debt issuances to current as they were callable within one year from December 31, 2003.	
 	 	 	
(2)	 	Distinguishes debt with various interest rates.	
 	 	 	
(3)	 	A+2 equals Libor plus 2%	
 	 	 	
(4)	 	A+ 3.5 equals Libor plus 3.5%	
 	 	 	
(5)	 	We have reclassified the long-term portions of these debt issuances to current, as they were callable within one year from December 6, 2003.	
 	 	 	
(6)	 	Discontinued operations	
     As of December 31, 2003, we have timely made scheduled payments on interest and/or principal on all of our recourse debt and were not in default under any of our related recourse debt instruments. However, a significant amount of our subsidiaries’ debt and other obligations contain terms that require that they be supported with letters of credit or cash collateral following a ratings downgrade or a default on our debt. As of December 31, 2003, as a result of the downgrades and loan defaults that we experienced in 2002, we estimate that we were in default of our obligations to post collateral of approximately $71.4 million, principally to fund contract termination penalties, revenue shortfall guarantees and late completion penalties related to NRG Peaker Finance Company LLC. On January 6, 2004, the debt held at NRG Peaker Finance Company LLC was restructured, and this collateral obligation ceased. As a result, we currently have no unmet cash collateral obligations outstanding.

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     Short Term Debt

     On December 23, 2003, we entered into a bank facility for up to $1.45 billion, or “New Credit Facility”, which included a $950.0 million, six and a half-year senior secured term loan, a $250.0 million funded letter of credit facility, and a four-year $250.0 million revolving line of credit, or “corporate revolver”. Portions of the corporate revolver are available as a swing-line facility and as a revolving letter of credit sub-facility. As of December 31, 2003, the corporate revolver was undrawn. The $250 million funded letter of credit is reflected as a funded deposit on the December 31, 2003 balance sheet.

Long-term Debt and Capital Leases

     Senior Securities

     As a result of our bankruptcy filing, we ceased recording accrued interest on the following unsecured facilities, as it was not probable of being paid. On December 5, 2003, concurrent with our emergence from bankruptcy, the following senior unsecured facilities were terminated in conjunction with certain settlement provisions. We have no outstanding obligations with respect to the following terminated debt facilities:
 	•	 	NRG Energy ROARS, due March 15, 2020, 7.97%; $250.0 million in outstanding principal, $25.3 million in accrued interest, and $41.1 million in contractually obligated interest at date of termination;	 	
 	
 	•	 	NRG Energy senior debentures, or “corporate units”, due May 16, 2006, 6.5%; $287.5 million in outstanding principal, $14.2 million in accrued interest, and $26.5 million in contractually obligated interest at date of termination;	 	
 	
 	•	 	NRG Energy senior notes due February 1, 2006, 7.625%; $125.0 million in outstanding principal, $7.7 million in accrued interest, and $14.2 million in contractually obligated interest at date of termination;	 	
 	
 	•	 	NRG Energy senior notes due July 15, 2006, 6.75%; $340.0 million in outstanding principal, $21.9 million in accrued interest, and $34.9 million in contractually obligated interest at date of termination;	 	
 	
 	•	 	NRG Energy senior notes due June 15, 2007, 7.50%; $250.0 million in outstanding principal, $19.4 million in accrued interest, and $30.7 million in contractually obligated interest at date of termination;	 	
 	
 	•	 	NRG Energy senior notes due June 1, 2009, 7.50%; $300.0 million in outstanding principal, $20.4 million in accrued interest, and $37.9 million in contractually obligated interest at date of termination;	 	
 	
 	•	 	NRG Energy senior notes due September 15, 2010, 8.25%; $350.0 million in outstanding principal, $34.5 million in accrued interest, and $56.9 million in contractually obligated interest at date of termination;	 	
 	
 	•	 	NRG Energy senior notes, due April 1, 2011, 7.75%; $350.0 million in outstanding principal, $31.2 million in accrued interest, and $51.5 million in contractually obligated interest at date of termination;	 	
 	
 	•	 	NRG Energy senior notes, due November 1, 2003, 8.00%; $240.0 million in outstanding principal, $17.5 million in accrued interest, and $34.6 million in contractually obligated interest at date of termination;	 	
 	
 	•	 	NRG Energy senior notes, due April 1, 2031, 8.625%; $340.0 million and $160 million in outstanding principal, and $49.7 million in accrued interest, and $83.0 million in contractually obligated interest at date of termination; and	 	
 	
 	•	 	NRG Energy corporate revolver, due March 8, 2003; $930.5 million in outstanding principal, $57.7 million in accrued interest, and $84.8 million in contractually obligated interest at date of termination.	 	
     As part of and concurrent with the emergence from bankruptcy, certain unsecured creditors received rights to $500.0 million of 10% NRG Energy senior notes, or “POR Notes” to be issued by us. However, the creditors accepted $500 million in cash in lieu of the POR Notes, on December 23, 2003 in conjunction with the financing described below. Accrued interest of $2.5 million was paid to these creditors based on the notional amount of the POR Notes. As of December 31, 2003, there were no outstanding obligations with respect to the POR Notes.

     On December 23, 2003, we issued $1.25 billion in 8% Second Priority Notes, due and payable on December 15, 2013. The Second Priority Notes are general obligations of ours. They are secured on a second-priority basis by security interests in all assets of ours,

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with certain exceptions, subject to the liens securing our obligations under the New Credit Agreement (described below) and any other priority lien debt. The notes are effectively subordinated to our obligations under the New Credit Facility and any other priority lien obligation, which will be secured on a first-priority basis by the same assets that secure the Second Priority Notes. The Second Priority Notes will be senior in right of payment to any future subordinated indebtedness. Interest on the Second Priority Notes accrues at the rate of 8.0% per annum and will be payable semi-annually in arrears on June 15 and December 15, commencing on June 15, 2004.

     Also on December 23, 2003, concurrently with the offering of the notes, we and PMI entered into the New Credit Facility for up to $1.45 billion with Credit Suisse First Boston, as Administrative Agent, and Lehman Commercial Paper, Inc., as Syndication Agent and a group of lenders. The New Credit Facility consists of a $950 million, six and a half-year senior secured term loan facility, a $250 million, funded letter of credit facility, and a four-year revolving credit facility in an amount of up to $250 million. Portions of the revolving credit facility are available as a swing-line facility and as a revolving letter of credit sub-facility. No borrowings had been made under the revolving credit facility as of December 31, 2003. Under the letter of credit facility, $1.7 million had been issued as of December 31, 2003.

     The New Credit Facility is secured by, among other things, first-priority perfected security interests in all of the property and assets owned at any time or acquired by us and our subsidiaries, other than the property and assets of certain excluded project subsidiaries, foreign subsidiaries and certain other subsidiaries, with some exceptions.

     Interest on the New Credit Facility consists of a spread of either 3% over prime or 4% over a LIBO rate, to be selected by the borrower. Other expenses associated with the New Credit Facility include commitment fees on the undrawn portion of the letter of credit facility, participation fees for the credit-linked deposit and other fees. As of December 31, 2003, we did not have an interest rate swap in place to hedge against fluctuations in prime or LIBO rates. On February 25, 2004 we amended the new credit facility to remove this requirement.

     Proceeds of the December 23, 2003 Second Priority Notes issuance and the New Credit Facility were used for the following purposes:
 	•	 	Repayment of secured debt held by NRG Northeast Generating LLC, including $556.5 million in outstanding principal, $1.1 million in accrued interest, and $8.3 million in a make-whole premium;	 	
 	
 	•	 	Repayment of secured debt held by NRG South Central Generating LLC, including $750.8 million in outstanding principal, $18.7 million in accrued interest, and $11.3 million in a make-whole premium;	 	
 	
 	•	 	Repayment of secured debt held by NRG Mid-Atlantic Generating LLC, including $406.6 million in outstanding principal and $4.1 million in accrued interest;	 	
 	
 	•	 	Funding of the $250 million letter of credit facility under the New Credit Facility;	 	
 	
 	•	 	Payment of cash in lieu of the $500 million, 10% POR Notes to be issued to certain unsecured creditors; and	 	
 	
 	•	 	Additional fees and expenses related to the transactions.	 	
     Significant affirmative covenants of the Second Priority Notes and the New Credit Facility include the provision of financial reports, reports of any events of default or developments that could have a material adverse effect, provision of notice with respect to changes in corporate structure or collateral. In addition, the borrower must maintain segregated cash accounts for certain deposits or settlements. A provision that the borrower enter into an interest-rate swap agreement on a portion of the term loan was waived by the lenders pursuant to an amendment to the New Credit Agreement.

     Significant negative covenants of the Second Priority Notes and the New Credit Facility include limitations on permitted indebtedness, including the provision of intercompany loans among certain subsidiaries and affiliates; permitted liens; permitted acquisitions and certain asset dispositions. In addition, certain financial ratio tests must be met.

     Events of default under the Second Priority Notes and the New Credit Facility include materially false representation or warranty; payment default on principal or interest; covenant defaults; cross-defaults to material indebtedness; our or a material subsidiary’s bankruptcy and insolvency; material unpaid judgments; ERISA events; failure to be perfected on any material collateral; and a change in control.

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     On January 28, 2004, we issued an additional $475.0 million in Second Priority Notes, under the same terms and indenture as our December 23, 2003 offering. Proceeds of the offering were used to prepay $503.5 million of the outstanding principal on the term loan under the New Credit Facility, described below, reducing the outstanding principal of the term loan from $950.0 million to $446.5 million.

Project Financings

     For discussion of NRG FinCo, the Audrain capital lease and LSP Pike Energy LLC see Note 24.

     The LSP Kendall Energy LLC credit facility is non-recourse to us and consists of a construction and term loan, working capital and letter of credit facilities. As of December 31, 2002, December 6, 2003 and December 31, 2003, there were borrowings totaling approximately $495.8 million, $489.2 million and $487.0 million, respectively, outstanding under the facility at a weighted average annual interest rate of 3.15%, 2.58% and 2.58%, respectively. In May 2002, LSP-Kendall Energy, LLC received a notice of default from Societe Generale, the administrative agent under LSP-Kendall’s Credit and Reimbursement Agreement dated November 12, 1999. The notice asserted that an event of default had occurred under the Credit and Reimbursement Agreement as a result of liens filed against the Kendall project by various subcontractors. In consideration of the borrower’s implementation of a plan to remove the liens, and our indemnification pursuant to an Indemnity Agreement dated June 28, 2002, of the lenders to the Kendall project from any claims or damages relating to these liens or any dispute or action involving the project’s EPC contractor, the administrative agent, with the consent of the required lenders under the Credit and Reimbursement Agreement, withdrew the notice of default and conditionally waived any default or event of default described therein. Discussions with the administrative agent regarding the liens continue. On August 25, 2003, LSP- Kendall Energy LLC entered into a Completion Extension and Amendment Agreement with the lenders and Societe Generale whereby certain extensions were granted in respect of project construction, lien removal and other items. The Completion Extension and Amendment Agreement prohibits LSP-Kendall Energy LLC from making any distributions to equity owners until January 1, 2005, and thereafter only when certain conditions are met. LSP-Kendall Energy LLC continues to be in default with respect to certain covenants, however, and is in discussions with the lenders regarding restructuring its indebtedness.

     In May 1999, LSP Energy Limited Partnership, or “Partnership” and LSP Batesville Funding Corporation, or “Funding” issued two series of Senior Secured Bonds, or “Bonds” in the following total principal amounts: $150 million 7.16% Series A Senior Secured Bonds due 2014 and $176 million 8.160% Series B Senior Secured Bonds due 2025. Interest is payable semiannually on each January 15 and July 15. In March 2000, a registration statement was filed by Partnership and Funding and became effective. The registration statement was filed to allow the exchange of the Bonds for two series of debt securities, or “Exchange Bonds”, which are in all material respects substantially identical to the Bonds. The Exchange Bonds are secured by substantially all of the personal property and contract rights of the Partnership and Funding. The Exchange Bonds are redeemable, at the option of Partnership and Funding, at any time in whole or from time to time in part, on not less than 30 nor more than 60 days prior notice to the holders of that series of Exchange Bonds, on any date prior to their maturity at a redemption price equal to 100% of the outstanding principal amount of the Exchange Bonds being redeemed and a make whole premium. In no event will the redemption price ever be less than 100% of the principal amount of the Exchange Bonds being redeemed plus accrued and unpaid interest thereon. Principal payments are payable on each January 15 and July 15 beginning July 15, 2001. Under the credit arrangements, the project is required to maintain minimum cash balances in certain reserve funds. Subject to funding these reserve accounts and anticipated working capital needs, and meeting certain debt coverage tests, the project may distribute any remaining cash to us. As of December 31, 2003, Batesville had sufficiently funded its reserve accounts, but did not meet its debt coverage test.

     In June 2002, NRG Peaker Finance Company LLC, or “NRG Peaker”, an indirect wholly owned subsidiary, completed the issuance of $325 million of Series A Floating Rate Senior Secured Bonds due 2019. The bonds bear interest at a floating rate equal to three-month LIBOR plus 1.07%. Interest on the bonds is payable on March 10, June 10, September 10 and December 10 of each year, commencing on September 10, 2002. NRG Peaker subsequently entered into an interest rate swap agreement pursuant to which it agreed to make 6.67% fixed rate interest payments and receive floating rate interest payments. XL Capital Assurance, or “XLCA”, guarantees principal, interest and swap payments, through a financial guaranty insurance policy. Such notes are also secured by substantially all of the assets of and/or membership interests in our subsidiaries: Bayou Cove Peaking Power LLC, Big Cajun I Peaking Power LLC, NRG Sterlington Power LLC, NRG Rockford LLC, NRG Rockford II LLC and NRG Rockford Equipment LLC. As of December 31, 2003, $311.4 million in aggregate principal remained outstanding on these bonds. XLCA accelerated the bonds due to cross-defaults on our debt and liens placed upon certain assets. On January 6, 2004, we and XLCA consummated a comprehensive restructuring arrangement which provides for, among other things, the provision of a letter of credit by us for the benefit of the secured parties in the NRG Peaker financing, the cure or waiver of all defaults under the original financing agreement and the mutual release of claims by the parties. With the exception of distributions to pay taxes, distributions to equity holders are subject to tests regarding NRG Peaker reserve funding and financial ratios.

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     In May 2001, our wholly-owned subsidiary, NRG Finance Company I LLC, or “NRG FinCo”, entered into a $2.0 billion revolving credit facility. The facility was established to finance the acquisition, development and construction of power generating plants located in the United States and to finance the acquisition of turbines for such facilities. The facility provided for borrowings of base rate loans and Eurocurrency loans and was secured by mortgages and security agreements in respect of the assets of the projects financed under the facility, pledges of the equity interests in the subsidiaries or affiliates of the borrower that own such projects, and by guaranties from each such subsidiary or affiliate. The NRG FinCo secured revolver was initially scheduled to mature on May 8, 2006; however, due to defaults hereunder by NRG FinCo and applicable guarantors, the lenders accelerated all outstanding obligations on November 6, 2002. As of our emergence, $1.1 billion was outstanding under the facility, and there was an aggregate of approximately $58 million of accrued but unpaid interest and commitment fees. Of this, $842.0 million was allowed in unsecured claims under NRG plan of reorganization, and was settled at the time of our emergence. The remaining balance will be satisfied when the NRG FinCo lenders exercise their perfected security interests in our Nelson, Audrain and Pike projects (see note 24).

     Meriden Gas Turbines LLC, or “MGT” is party to a $0.5 million Promissory Note and Security Agreement with PowerSource LLC, issued and entered into on February 13, 2003. MGT used the proceeds of the note issuance to allow the release of a lien and claim on certain MGT assets, and for costs associated with the transport of certain equipment to the MGT site. The note became due and payable on May 14, 2003. We expect to repay this note with the proceeds from the sale of the MGT assets in 2004.

     In March 2001, we increased our ownership interest in Penobscot Energy Recovery Company, or “PERC”, which resulted in the consolidation of our equity investment in PERC. As a result, the assets and liabilities of PERC became part of our consolidated assets and liabilities. Upon completion of the transaction, we recorded approximately $37.9 million of outstanding Finance Authority of Maine Electric, or “FAME” Rate Stabilization Revenue Refunding Bonds Series 1998, or “FAME bonds” which were issued on PERC’s behalf by FAME in June 1998. The face amount of the bonds that were initially issued was approximately $44.9 million and was used to repay the Floating Rate Demand Resource Revenue Bonds issued by the Town of Orrington, Maine on behalf of PERC. The FAME bonds are fixed rate bonds with yields ranging from 3.75% to 5.2%. The weighted average yield on the FAME bonds is approximately 5.1%. The FAME bonds are subject to mandatory redemption in annual installments of varying amounts through July 1, 2018. Beginning July 1, 2008 the FAME bonds are subject to redemption at the option of PERC at a redemption price equal to 102% through June 30, 2009, 101% for the period July 1, 2009 to June 30, 2010 and 100% thereafter, of the principal amount outstanding, plus accrued interest. The loan agreement with FAME contains certain restrictive covenants relating to the FAME bonds, which restrict PERC’s ability to incur additional indebtedness, and restricts the ability of the general partners to sell, assign or transfer their general partner interests. The bonds are collateralized by liens on substantially all of PERC’s assets. As of December 31, 2003, $26.3 million in principal remains outstanding.

     In November 2001, NRG McClain LLC entered into a $181.0 million term loan and $8.0 million working capital facility with Westdeutsche Landesbank Girozentrale, New York branch, as agent to repay an outstanding term loan used to finance the acquisition of the McClain generating facility (non-recourse to us). The final maturity date of the facility is November 30, 2006. As of December 31, 2002 and 2003, the aggregate amount outstanding under this facility was $157.3 million and $156.5 million, respectively. During the period ended December 31, 2002 and 2003, the weighted average interest rate of such outstanding borrowings was 4.51% and 5.89%, respectively. On September 17, 2002, NRG McClain LLC received notice from the agent bank that the project loan was in default as a result of our downgrades and of defaults on material obligations under the Energy Management Services Agreement. On August 19, 2003, NRG McClain signed an asset purchase agreement with Oklahoma Gas and Electric Company for substantially all of the assets of McClain and contemporaneously filed for bankruptcy pursuant to the asset purchase agreement. Upon consummation of the asset sale we anticipate that all proceeds from the sale will be used to repay outstanding project debt under the secured term loan and working capital facility. On December 18, 2003, FERC issued an order setting the application for hearing to determine remedies FERC could impose as a condition of any approval for the transaction. This sale will not be completed until FERC approval is received. NRG McClain is recorded as a discontinued operation in the accompanying balance sheets.

     The Camas Power Boiler LP notes are secured principally by its long-term assets. In accordance with the terms of the note agreements, Camas Power Boiler LP is required to maintain compliance with certain financial covenants primarily related to incurring debt, disposing of assets, and affiliate transactions. Camas Power Boiler was in compliance with these covenants at December 31, 2003. Distributions to us from Camas are permitted quarterly, contingent upon the project sufficiently funding debt service accounts, and meeting certain covenants and conditions. As of December 31, 2003, Camas met all requirements for distributions.

     In July 2002, NRG Energy Center Minneapolis LLC, or “MEC”, an indirect wholly owned subsidiary, entered into an agreement allowing it to issue senior secured promissory notes in the aggregate principal amount of up to $150 million. In July 2002, under this agreement, MEC issued $75 million of bonds in a private placement. Two series of notes were issued in July 2002, the $55 million

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Series A-Notes dated July 3, 2002, which matures on August 1, 2017 and bears an interest rate of 7.25% per annum and the $20 million Series B-Notes dated July 3, 2002, which matures on August 1, 2017 and bears an interest rate of 7.12% per annum. NRG Thermal LLC, a directly held, wholly-owned subsidiary, which owns 100% of MEC, pledged its interests in all of its district heating and cooling investments throughout the United States as collateral. NRG Thermal and MEC are required to maintain compliance with certain financial covenants primarily related to incurring debt, disposing of assets, and affiliate transactions. In August 1993, MEC issued $84 million of 7.31% senior secured notes, due June 15, 2013. The three MEC notes contain a covenant providing the lender the option to choose prepayment of the notes if, among other things, Xcel Energy no longer directly or indirectly owns a controlling interest in NRG Thermal. Xcel Energy no longer owns a controlling interest in NRG Thermal as a result of our emergence from bankruptcy. In anticipation of the change in control, NRG Thermal has entered into a forbearance agreement with the lender to allow time to negotiate a modified loan covenant package that would enable the lender to choose not to exercise its change in control option. Until a new loan covenant package has been developed, terms of the forbearance agreement prevent MEC or its subsidiaries from making distributions to us. The forbearance agreement expires June 1, 2004. As a result of the forbearance agreement, NRG Thermal and MEC were in compliance with their credit covenants at December 31, 2003.

     STS Hydropower, LTD, or “STS Hydropower” which is indirectly 50% owned by NEO Corporation, or “NEO”, our wholly-owned subsidiary, entered into a Note Purchase Agreement in March 1995 with Allstate Life Insurance Co., or “Allstate”. Allstate purchased from STS Hydropower $22.1 million of 9.155% senior secured debt due December 30, 2016. The agreement was amended in 1996 to add $0.7 million of 8.24% senior secured debt due March 2011. The debt is secured by substantially all assets of and interest in STS Hydropower. Because of poor hydroelectric output due to drought conditions, no principal or interest payments have been made on this loan facility since October 2001. In May 2003, the facility was restructured and currently has a maturity of March 2023 and an interest rate of 9.133%. As of December 31, 2003, all required covenants under the restructured facility had been met and $25.2 million of principal was outstanding.

     In September 1999, Northbrook New York LLC, or “NNY”, which is indirectly owned by NEO, entered into a $17.5 million term loan agreement with Heller Financial. In December 2001, the credit agreement with Heller Financial was amended to include $2.6 million of financing for Northbrook Carolina Hydro, LLC, or “NCH”, which is indirectly 50% owned by NEO, and to cross-collateralize the NNY and NCH notes. Heller Financial was subsequently purchased by GE Capital Services, which assumed the notes. The loan facilities are secured by substantially all hydroelectric assets of and membership interests in NCH and NNY. The NNY facility bears an interest rate of LIBOR plus 3% and matures in December 2018. The NCH facility bears interest at an interest rate of LIBOR plus 4% and matures in December 2016. As of December 31, 2003, the outstanding principal balance on the NNY facility and the NCH facility was $17.2 million and $2.5 million, respectively. On December 2001, NCH purchased a $0.3 million subordinated note from NEO. This subordinated note accrues interest at 11% per annum, and no payment is due until maturity on December 31, 2018.

     In September 2000, Flinders Power Finance Pty Ltd, or “Flinders Power”, an Australian wholly owned subsidiary, entered into a twelve year AUD $150 million cash advance facility (US $81.4 million at September 2000). As of December 31, 2002 and 2003, there remains AUD$143.4 million (US$80.5 million) and AUD$135.0 million (US$101.6 million) outstanding under this facility, respectively. The interest has fixed and variable components. At December 31, 2002 and 2003, the interest rate was 6.49% and 7.53%, respectively and is paid semi-annually. Principal payments commence in 2006 and the facility will be fully paid in 2012.

     In March 2002, Flinders Power entered into a 10 year AUD$165 million (US$85.4 million at March 2002) floating rate loan facility for the purpose of refurbishing the Flinders Playford generating station. As of December 31, 2002 and 2003, the Company had drawn AUD$33.3 million (US$18.7 million) and AUD$114.3 million (US$86.0 million), respectively, of this facility. The interest rate has fixed and variable components. The interest rate at December 31, 2002 and 2003 was 6.14% and 7.03%, and is paid semi-annually. Principal payments for the refurbishment facility commence in 2005. Upon our downgrades in 2002, there existed a potential default under these facility agreements related to the funding of reserve accounts. On May 13, 2003, Flinders Power and its lenders entered into a Second Supplemental Deed, which resolved these potential defaults. As part of the terms of that Second Supplemental Deed, part of the refurbishment facility was voluntarily cancelled by Flinders Power so as to reduce the total available commitment from AUD$165 million to AUD$137 million (US$103.1 million).

     In connection with our acquisition of a controlling interest in the COBEE facilities, we assumed non-recourse long-term debt that is due in 18 semi-annual installments of varying amounts beginning January 31, 1999 and ending July 31, 2007. The loan agreement provides an A Loan of up to $30 million and a B Loan of up to $45 million. The balance of the A and B loans was $31.8 million as of December 31, 2003. Interest is payable semi-annually in arrears at a rate equal to 6-month LIBOR plus a margin of 4.5% on the A Loan and 6-month LIBOR plus a margin of 4.0% on the B Loan. The A Loan and the B Loan are collateralized by a mortgage on substantially all of COBEE’s assets.

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     In connection with our purchase of PowerGen’s interest in Saale Energie GmbH, we have recognized a non-recourse capital lease on our balance sheet in the amount of $325.6 million and $342.5 million, as of December 31, 2002 and 2003, respectively. The capital lease obligation is recorded at the net present value of the minimum lease obligation payable over the lease’s remaining period of 19 years. In addition, a direct financing lease was recorded in notes receivable in the amount of approximately $366.4 million, $435.0 million and $451.4 million, as of December 31, 2002, December 6, 2003 and December 31, 2003, respectively.

     Hsin Yu, which is approximately 63% indirectly owned by us, entered into a NT$2,700.0 million syndicated loan arrangement to finance construction of what was to be the first phase of a multi-phase cogeneration facility. Chiao Tung Bank led the original financing. Principal covenants of the syndicated facility include maintaining a debt to equity ratio below 250% until 2006, and a ratio below 200% thereafter, and maintaining a debt service coverage ratio above 1.1, starting in 2004. The fair value adjustment reflects the uncertainty of repayment of such obligations from project cash flows.

     Annual maturities of long-term debt and capital leases for the years ending after December 31, 2003 are as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Discontinued	 	Continuing	 	 	
 	 	Operations

	 	Operations

	 	Total

	
 	 	 	(In thousands)	 	
2004	 	$	105,635	 	 	$	901,242	 	 	$	1,006,877	 	
2005	 	 	22,955	 	 	 	112,684	 	 	 	135,639	 	
2006	 	 	18,455	 	 	 	92,034	 	 	 	110,489	 	
2007	 	 	19,150	 	 	 	72,074	 	 	 	91,224	 	
2008	 	 	14,935	 	 	 	65,159	 	 	 	80,094	 	
Thereafter	 	 	269,410	 	 	 	2,973,348	 	 	 	3,242,758	 	

 	 	 	 	

 	 	 	 	

 	 	
Total	 	$	450,540	 	 	$	4,216,541	 	 	$	4,667,081	 	

 	 	 	 	

 	 	 	 	

 	 	
     Future minimum lease payments for capital leases included above at December 31, 2003 are as follows:
 	 	 	 	 	
 	 	(In thousands)	
2004	 	$	125,020	 	
2005	 	 	127,608	 	
2006	 	 	89,875	 	
2007	 	 	76,647	 	
2008	 	 	68,940	 	
Thereafter	 	 	689,165	 	

 	 	
Total minimum obligations	 	 	1,177,255	 	

 	 	
Interest	 	 	594,519	 	

 	 	
Present value of minimum obligations	 	 	582,736	 	
Current portion	 	 	76,280	 	

 	 	
Long-term obligations	 	$	506,456	 	

 	 	
     Assets related to our capital leases were revalued as of December 6, 2003, to $171.0 million and remained at $171.0 million with no accumulated amortization at December 31, 2003, as the amounts have been recorded at recoverable values. Total net book value related to these assets at December 31, 2002 was $258.2 million, net of $2.3 million of accumulated amortization.

Note 18 — Capital Stock

Reorganized Capital Structure

     In connection with the consummation of our plan of reorganization, on December 5, 2003 all shares of our old common stock were canceled and 100,000,000 shares of new common stock of NRG Energy were distributed pursuant to such plan to the holders of certain classes of claims. A certain number of shares of common stock were issued for distribution to holders of disputed claims as such claims are resolved or settled. In the event our disputed claims reserve is inadequate, it is possible we would have to issue additional shares of our common stock to satisfy such pre-petition claims or contribute additional cash proceeds. See Note 24 — Disputed Claims Reserve. Our authorized capital stock consists of 500,000,000 shares of NRG Energy common stock and 10,000,000 shares of Serial Preferred Stock. Further, a total of 4,000,000 shares of our common stock, representing approximately 4% of our outstanding common stock, are available for issuance under our long-term incentive plan.

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     In addition to our issuance of new common stock, on December 23, 2003, we completed a note offering consisting of $1.25 billion of 8% Second Priority Senior Secured Notes due 2013, and we entered into a new credit facility consisting of a $950.0 term loan facility, a $250.0 million funded letter of credit facility and a $250 million revolving credit facility. We used the proceeds of these offerings to retire certain project level debt, pay certain unsecured creditors and relieve associated cash traps. In January of 2004, we completed a supplementary note offering whereby we issued an additional $475 million of 8% Second Priority Senior Secured Notes due 2013 at a premium and used the proceeds there from to repay a portion of the $950.0 million term loan. As of March 1, 2004, the outstanding principal balance on the notes was $1.725 billion, the principal amount outstanding under the term loan was $446.5 million and $147.5 million remains available under the funded letter of credit facility. As of March 1, 2004, we had not drawn down on our revolving credit facility. Finally, in connection with the consummation of our plan of reorganization, we issued to Xcel Energy a $10.0 million non-amortizing promissory note, which will accrue interest at a rate of 3% per annum and mature 2.5 years after the effective date of our plan of reorganization.

     As part of our plan of reorganization, we eliminated approximately $5.2 billion of corporate level bank and bond debt and approximately $1.3 billion of additional claims and disputes through our distribution of new common stock and $1.04 billion in cash among our unsecured creditors. In addition to the debt reduction associated with the restructuring, we used the proceeds of the recent note offering and borrowings under the New Credit Facility to retire approximately $1.7 billion of project-level debt.

     For additional information on our short term and long term borrowing arrangements, see Note 17.

Sale of Stock

     In June 2000, we sold 32.4 million shares of common stock at $15 per share. Net proceeds from the offering were $453.7 million. At that time we were authorized to issue capital stock consisting of 550,000,000 shares of common stock, and 250,000,000 shares of Class A common stock. At December 31, 2000, there were approximately 32,396,000 shares of common stock, and 147,605,000 shares of Class A common stock issued and outstanding.

     In March 2001, we completed the sale of 18.4 million shares of common stock for an initial price of $27 per share. The offering was completed with all 18.4 million shares of common stock being sold including the over-allotment shares of 2.4 million. We received gross proceeds from the issuance of $496.6 million. Net proceeds from the issuance were $473.4 million after deducting underwriting discounts, commissions and estimated offering expenses. The net proceeds were used in part to reduce amounts outstanding under our short-term bridge credit agreement, which was used to finance, in part, our acquisition of the LS Power assets.

     At December 31, 2001, there were approximately 50,939,875 shares of common stock, and 147,605,000 shares of Class A common stock issued and outstanding.

     On June 3, 2002, Xcel Energy completed its exchange offer for the 26% of our common shares that had been previously publicly held. Xcel Energy issued to our shareholders 0.50 shares of Xcel Energy common stock in exchange for each outstanding share of our common stock.

Incentive Compensation Plans

     In June 2000, we adopted an incentive compensation plan, or “the Stock Plan”, which was approved by shareholders in June 2001. We accounted for this plan under the recognition and measurement provisions of APB Opinion No. 25,  “Accounting for Stock Issued to Employees,”  and related Interpretations. During 2002, the Stock Plan, and all grants under the plan, were adopted by the Xcel Energy Incentive Stock Plan. There were no grants to our employees under the Xcel Energy Incentive Stock Plan. During 2001, we recognized approximately $1.9 million of stock based compensation expense under the New Stock Plan. In 2002, we recognized income due to the net reduction of our compensation expense accrual by approximately $2.3 million for terminated stock options during the period. The amount was reported as a reduction of compensation expense for the year ended December 31, 2002.

     Effective January 1, 2003, we adopted the fair value recognition provisions of SFAS Statement No. 123, “Accounting for Stock-Based Compensation”  or “SFAS No. 123.” In accordance with SFAS Statement No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure”  or “SFAS No. 148”, we adopted SFAS No. 123 under the prospective transition method which requires the application of the recognition provisions to all employee awards granted, modified, or settled after the beginning of the fiscal year in which the recognition provisions are first applied. As a result, we recognized compensation expense for any grants issued on or after January 1, 2003. There were no grants issued during the period from January 1, 2003 through December 4, 2003.

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     During 2003, we recognized approximately $540,000 of stock based compensation expense under the Long-Term Incentive Plan, approximately $424,000 related to stock options and approximately $116,000 related to restricted stock. In December 2003, we adopted a new long-term incentive plan, or “the Long-Term Incentive Plan”, which is described below.

Long-Term Incentive Plan

     The Long-Term Incentive Plan became effective upon our emergence from bankruptcy. The long-term incentive plan provides for grants of stock options, stock appreciation rights, restricted stock, performance awards, deferred stock units and dividend equivalent rights. Our directors, officers and employees, as well as other individuals performing services for, or to whom an offer of employment has been extended by us, are eligible to receive grants under the long-term incentive plan. The purpose of the long-term inventive plan is to promote our long-term growth and profitability by providing these individuals with incentives to maximize stockholder value and otherwise contribute to our success and to enable us to attract, retain and reward the best available persons for positions of responsibility.

     A total of 4,000,000 shares of our common stock, representing approximately 4% of our outstanding common stock, are available for issuance under the long-term incentive plan, subject to adjustment in the event of a reorganization, recapitalization, stock split, reverse stock split, stock dividend, combination of shares, merger or similar change in our structure or our outstanding shares of common stock.

     The compensation committee of our board of directors will administer the long-term incentive plan. If for any reason a compensation committee has not been appointed by our board to administer the long-term incentive plan, our board of directors will have the authority to administer the plan and to take all actions under the plan.

     The following is a summary of the material terms of the long-term incentive plan, but does not include all of the provisions of the plan.

     Eligibility. Our directors, officers and employees, as well as other individuals performing services for, or to whom an offer of employment has been extended by, us are eligible to receive grants under the long-term incentive plan. In each case, the compensation committee will select the actual grantees.

     Stock Options. Under the long-term incentive plan, the compensation committee may award grants of incentive stock options conforming to the requirements of Section 422 of the Internal Revenue Code or non-qualified stock options. The compensation committee may not award to any one person in any calendar year options to purchase more than 1,000,000 shares of common stock. In addition, it may not award incentive stock options first exercisable in any calendar year whose underlying shares have a fair market value greater than $100,000, determined at the time of grant.

     The compensation committee will determine the exercise price of any options granted under the long-term incentive plan. However, the exercise price of any option may not be less than 100% of the fair market value of a share of our common stock on the date of grant, and the exercise price of an incentive stock option granted to a person who owns stock constituting more than 10% of the voting power of all classes of our stock may not be less than 110% of the fair market value of a share of our common stock on the date of grant.

     Unless the compensation committee determines otherwise, the exercise price of any option may be paid in any of the following ways:
•	 	in cash;	 	 	
 	
•	 	by delivery of shares of common stock with a fair market value equal to the exercise price;	 	 	
 	
•	 	by means of any cashless exercise procedure approved by the compensation committee; or	 	 	
 	
•	 	by any combination of the foregoing.	 	 	
     The compensation committee will determine the term of each option in its discretion. However, no term may exceed 10 years from the date of grant or, in the case of an incentive stock option granted to a person who owns stock constituting more than 10% of the voting power of all classes of our stock, five years from the date of grant. In addition, all options under the long-term incentive plan,

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whether or not then exercisable, generally will cease vesting when a grantee ceases to be a director, officer or employee of, or to otherwise perform services for, us. Vested options will generally expire 90 days after the date of cessation of service.

     There will be exceptions depending upon the circumstances of cessation. In the case of a grantee’s death, all options will become fully vested and will remain exercisable for a period of one year after the date of death. In the case of a grantee’s termination due to disability, vested options will remain exercisable for a period of one year after the date of termination due to disability while his or her unvested options will be forfeited. In the event of retirement, a grantee’s vested options will remain exercisable for a period of two years after the date of retirement while his or her unvested options will be forfeited. Upon termination for cause, all options will terminate immediately. Upon a change in control of NRG Energy, all of the options will become fully vested and will remain exercisable until the expiration date of the options. In addition, the compensation committee will have the authority to grant options that will become fully vested and exercisable automatically upon a change in control, whether or not the grantee is subsequently terminated.

     Upon a reorganization, merger, consolidation or sale or other disposition of all or substantially all of our assets, the compensation committee may cancel any or all outstanding options under the long-term incentive plan in exchange for payment of an amount equal to the portion of the consideration that would have been payable to the grantees in the transaction if their options had been fully exercised immediately prior to the transaction, less the exercise price that would have been payable, or if the exercise price is greater than the consideration that would have been payable in the transaction, then for no consideration or payment.

     Stock Appreciation Rights. Under the long-term incentive plan, the compensation committee may grant stock appreciation rights, or SARs, alone or in tandem with options, subject to terms and conditions as the compensation committee may specify. SARs granted in tandem with options will become exercisable only when, to the extent and on the conditions that the related options are exercisable, and they will expire at the same time the related options expire. The exercise of an option will result in the immediate forfeiture of any related SAR to the extent the option is exercised, and the exercise of a SAR results in the immediate forfeiture of any related option to the extent the SAR is exercised.

     Upon exercise of a SAR, the grantee will receive an amount in cash, shares of our common stock or our other securities equal to the difference between the fair market value of a share of common stock on the date of exercise and the exercise price of the SAR or, in the case of a SAR granted in tandem with options, of the option to which the SAR relates, multiplied by the number of shares as to which the SAR is exercised. Unless otherwise provided in the grantee’s grant agreement, each SAR will be subject to the same termination and forfeiture provisions as the stock options described above.

     Restricted Stock. Under the long-term incentive plan, the compensation committee may award restricted stock in the amounts that it determines in its discretion. Each grant of restricted stock will be evidenced by a grant agreement, which will specify the applicable restrictions on such shares and the duration of the restrictions (which will generally be at least six months). A grantee will be required to pay us at least the aggregate par value of any shares of restricted stock within ten days of the grant, unless the shares are treasury shares. Unless otherwise provided in the grantee’s grant agreement, each unit or share of restricted stock will be subject to the same termination and forfeiture provisions as the stock options described above.

     Performance Awards. Under the long-term incentive plan, the compensation committee may grant performance awards contingent upon achievement by the grantee, us or any of our divisions of specified performance criteria, such as return on equity, over a specified performance cycle, as determined by the compensation committee. Performance awards may include specific dollar-value target awards; performance units, the value of which will be determined by the compensation committee at the time of issuance; and/or performance shares, the value of which will be equal to the fair market value of common stock. The value of a performance award may be fixed or may fluctuate based on specified performance criteria. A performance award may be paid out in cash, shares of our common stock or our other securities.

     A grantee must be a director, officer or employee of, or otherwise perform services for, us at the end of the performance cycle in order to be entitled to payment of a performance award issued in respect of such cycle, provided that unless otherwise provided in the grantee’s grant agreement, each performance award will be subject to the same termination and forfeiture provisions as the stock options described above.

     Deferred Stock Units. Under the long-term incentive plan, the compensation committee may grant deferred stock units from time to time in its discretion. A deferred stock unit will entitle the grantee to receive the fair market value of one share of common stock at the end of the deferral period, which will be no less than one year. The payment of the value of deferred stock units may be made by us in shares of our common stock, cash or both. If a grantee ceases to be a director, officer or employee of, or otherwise perform

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services for, us upon his or her death prior to the end of the deferral period, the grantee will receive payment of his or her deferred stock units which would have matured or been earned at the end of the deferral period as if the deferral period has ended as of the date of his or her death. In the event of a termination due to disability or retirement prior to the end of the deferral period, the grantee will receive payment of his or her deferred stock units at the end of the deferral period. If a grantee ceases to be a director, officer or employee of, or otherwise perform services for, us for any other reason, his or her unvested deferred stock units will immediately be forfeited. Upon a change in control in NRG Energy, a grantee will receive payment of his or her deferred stock units as if the deferral period has ended as of the date of the change in control.

     Dividend Equivalent Rights. Under the long-term incentive plan, the compensation committee may grant a dividend equivalent right entitling the grantee to receive amounts equal to all or any portion of the dividends that would be paid on shares of our common stock covered by an award if those shares had been delivered to the grantee pursuant to the award, subject to terms and conditions as the committee may specify.

     Vesting, Withholding Taxes and Transferability of All Awards. The terms and conditions of each award made under the long-term incentive plan, including vesting requirements, will be set forth consistent with the plan in a written agreement with the grantee. Except in limited circumstances and unless the compensation committee determines otherwise, no award under the long-term incentive plan may vest and become exercisable within six months of the date of grant.

     Unless the compensation committee determines otherwise, a participant may elect to deliver shares of common stock, or to have us withhold shares of common stock otherwise issuable upon exercise of an option or a SAR or deliverable upon grant or vesting of restricted stock or the receipt of common stock, in order to satisfy our tax withholding obligations in connection with any exercise, grant or vesting.

     Unless the compensation committee determines otherwise, no award made under the long-term incentive plan will be transferable other than by will or the laws of descent and distribution, and each option, SAR or performance award may be exercised only by the grantee or his or her executor, administrator, guardian or legal representative, or by a family member of the grantee if he or she has acquired the option, SAR or performance award by gift or qualified domestic relations order.

     Amendment and Termination of the Long-Term Incentive Plan. The board of directors or the compensation committee may amend or terminate the long-term incentive plan in its discretion, except that no amendment will become effective without prior approval of our stockholders if approval is required by applicable law or regulations, including any NASDAQ or stock exchange listing requirements, if the amendment would remove a provision of the long-term incentive plan which, without giving effect to the amendment, is subject to shareholder approval or if the amendment would directly or indirectly increase the share limit of 4,000,000 shares. If not otherwise terminated, the long-term incentive plan will terminate on the tenth anniversary of the effective date of our plan of reorganization, which was December 5, 2003.

     In December 2003, we issued one stock option grant for a total of 632,751 shares of common stock under the Long-Term Incentive Plan. These options have a three-year graded vesting schedule and become exercisable through the year 2006 at a price of $24.03. Total compensation expense under the stock option grant is approximately $8.3 million. Compensation expense for the year ended December 31, 2003 was approximately $0.4 million. Compensation expense for the years ended December 31, 2004, December 31, 2005 and December 31, 2006 will be approximately $4.9 million, $2.2 million and $0.8 million, respectively. At December 31, 2003, no employee stock options were exercisable. Stock option transactions were:

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 	 	 	 	 	 	Weighted-	
 	 	 	 	 	 	Average	
 	 	 	 	 	 	Exercise	
 	 	Shares

	 	Price

	
Outstanding at January 1, 2003	 	 	—	 	 	$	—	 	
Granted	 	 	632,751	 	 	 	24.03	 	
Exercised	 	 	—	 	 	 	—	 	
Canceled or expired	 	 	—	 	 	 	—	 	
Outstanding at December 6, 2003	 	 	632,751	 	 	 	24.03	 	

 	 	 	 	

 	 	
Exercisable December 6, 2003	 	 	—	 	 	 	—	 	

 	 	 	 	

 	 	
Granted	 	 	—	 	 	 	—	 	
Exercised	 	 	—	 	 	 	—	 	
Canceled or expired	 	 	—	 	 	 	—	 	
Outstanding at December 31, 2003	 	 	632,751	 	 	 	24.03	 	

 	 	 	 	

 	 	
Exercisable December 31, 2003	 	 	—	 	 	$	—	 	

 	 	 	 	

 	 	
Weighted-average fair value of options granted during the year	 	 	 	 	 	$	13.17	 	
     The following table summarizes information about stock options outstanding at December 31, 2003:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Options Outstanding

	 	Options Exercisable

	
 	 	 	 	 	 	Weighted-	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Average	 	Weighted-	 	 	 	 	 	Weighted-	
 	 	 	 	 	 	Remaining	 	Average	 	 	 	 	 	Average	
 	 	Total	 	Life (In	 	Exercise	 	Total	 	Exercise	
Range of exercise prices

	 	Outstanding

	 	Years)

	 	Price

	 	Exercisable

	 	Price

	
$24.03	 	 	632,751	 	 	 	10.0	 	 	$	24.03	 	 	 	—	 	 	$	—	 	
     The fair value of the stock option grant was estimated on the date of grant using the Black-Scholes option-pricing model, with the following weighted-average assumptions used for grants in 2003.
 	 	 	 	 	
 	 	2003

	
Dividends per year	 	 	—	 	
Expected volatility	 	 	35.70	 	
Risk-free interest rate	 	 	4.24	 	
Expected life (years)	 	 	10	 	
     In December 2003, we issued 173,394 restricted stock units under the Long-Term Incentive Plan. These units will fully vest in December 2006. Total compensation expense under the restricted stock grant is approximately $4.2 million. Compensation expense for the year ended December 31, 2003 was approximately $0.1 million. Compensation expense for the years ended December 31, 2004, December 31, 2005 and December 31, 2006 will be approximately $1.4 million, $1.4 million and $1.3 million, respectively. The weighted-average fair value of our restricted stock units for 2003 is $24.03.

Note 19 — Earnings Per Share

     Basic earnings per common share were computed by dividing net income by the weighted average number of common stock shares outstanding. Shares issued during the year are weighted for the portion of the year that they were outstanding. Shares of common stock granted to our officers and employees are included in the computation only after the shares become fully vested. Diluted earnings per share is computed in a manner consistent with that of basic earnings per share while giving effect to all potentially dilutive common shares that were outstanding during the period. The dilutive effect of the potential exercise of outstanding options to purchase shares of common stock is calculated using the treasury stock method. The reconciliation of basic earnings per common share to diluted earnings per share is shown in the following table:

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 	 	Reorganized NRG	
 	 	For the Period	
 	 	December 6 -	
 	 	December 31, 2003

	
 	 	(In thousands,	
 	 	except per share data)	
Basic earnings per share	 	 	 	 	
Numerator:	 	 	 	 	
Income from continuing operations	 	$	11,337	 	
Discontinued operations, net of tax	 	 	(312	)	

 	 	
Net income	 	$	11,025	 	

 	 	
Denominator:	 	 	 	 	
Weighted average number of common shares outstanding	 	 	100,000	 	
Income from continuing operations	 	$	0.11	 	
Discontinued operations, net of tax	 	 	—	 	

 	 	
Net income	 	$	0.11	 	

 	 	
Diluted earnings per share	 	 	 	 	
Numerator	 	 	 	 	
Income from continuing operations	 	$	11,337	 	
Discontinued operations, net of tax	 	 	(312	)	

 	 	
Net income	 	$	11,025	 	

 	 	
Denominator:	 	 	 	 	
Weighted average number of common shares outstanding	 	 	100,000	 	
Incremental shares attributable to the assumed exercise of outstanding stock options (treasury stock method)	 	 	—	 	
Incremental shares attributable to the issuance of unvested stock grants (treasury stock method)	 	 	60	 	

 	 	
Total dilutive shares	 	 	100,060	 	

 	 	
Income from continuing operations	 	$	0.11	 	
Discontinued operations, net of tax	 	 	—	 	

 	 	
Net income	 	$	0.11	 	

 	 	
     The options to purchase 632,751 shares of common stock at a price of $24.03 per share were not included in the computation because the options’ exercise price was greater than the average market price of the common shares and therefore the effect would be anti-dilutive.

Note 20 — Segment Reporting

In connection with our emergence from bankruptcy and the new management team, we determined that it was necessary to adjust our segment reporting disclosures to more closely align our disclosures with the realignment of our management team. Accordingly, we have expanded our domestic geographical disclosures and collapsed our international geographical disclosures related to our wholesale power generation segment. In addition, our other segments have been further refined. As a result of these changes, we have retroactively recast our prior period disclosures in a consistent manner.

We conduct the majority of our business within five reportable operating segments. All of our other operations are presented under the “All Other” category. Our reportable operating segments consist of Wholesale Power Generation — Northeast, Wholesale Power Generation — South Central, Wholesale Power Generation — West Coast, Wholesale Power Generation — Other North America and Wholesale Power Generation — Australia. These reportable segments are distinct components with separate operating results and management structures in place. Included in the All Other category are our Wholesale Power Generation — Other International operations, our Alternative Energy operations, our Non-Generation operations and an Other component which includes primarily our corporate charges (primarily interest expense) that have not been allocated to the reportable segments and the remainder of our operations which are not significant. We have presented this detail within the All Other category as we believe that this information is important to a full understanding of our business.

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 	 	Reorganized NRG
December 6, 2003 Through December 31, 2003	
 	 	Wholesale Power Generation

	
 	 	 	 	 	 	South	 	 	 	 	 	Other North	 	 	
 	 	Northeast

	 	Central

	 	West Coast

	 	America

	 	Australia

	
 	 	(In thousands)	
Operations	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Revenues	 	$	69,191	 	 	$	26,609	 	 	$	(268	)	 	$	5,377	 	 	$	11,947	 	
Depreciation and amortization	 	 	4,604	 	 	 	2,561	 	 	 	58	 	 	 	1,639	 	 	 	1,475	 	
Reorganization items	 	 	241	 	 	 	27	 	 	 	—	 	 	 	—	 	 	 	—	 	
Operating Income/(Loss)	 	 	11,330	 	 	 	4,530	 	 	 	(445	)	 	 	948	 	 	 	87	 	
Minority interest in earnings of consolidated subsidiaries	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(134	)	 	 	—	 	
Equity in earnings of unconsolidated affiliates	 	 	—	 	 	 	—	 	 	 	9,979	 	 	 	1,836	 	 	 	997	 	
Other income (expense), net	 	 	(267	)	 	 	99	 	 	 	—	 	 	 	162	 	 	 	274	 	
Interest expense	 	 	(2,976	)	 	 	(4,133	)	 	 	—	 	 	 	(3,643	)	 	 	(707	)	
Income/(Loss) From Continuing Operations Before Income Taxes	 	 	8,087	 	 	 	496	 	 	 	9,534	 	 	 	(831	)	 	 	651	 	
Income Tax Expense/(Benefit)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	357	 	 	 	(298	)	
Income/(Loss) from Continuing Operations	 	 	8,087	 	 	 	496	 	 	 	9,534	 	 	 	(1,188	)	 	 	949	 	
Income/(Loss) on Discontinued Operations, net of Income Taxes	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(248	)	 	 	—	 	
Net Income/(Loss)	 	 	8,087	 	 	 	496	 	 	 	9,534	 	 	 	(1,436	)	 	 	949	 	
Balance Sheet	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Equity investments in affiliates	 	 	1,281	 	 	 	—	 	 	 	304,267	 	 	 	96,249	 	 	 	136,129	 	
Total Assets	 	$	2,178,681	 	 	$	1,128,404	 	 	$	355,184	 	 	$	2,052,100	 	 	$	945,096	 	

 	 	Reorganized NRG
December 6, 2003 Through December 31, 2003

	
 	 	All Other

	 	 	 	 	
 	 	Wholesale
Power	 	 	 	 	
 	 	Generation

	 	 	 	 	 	 	 	 	
 	 	Other	 	Alternative	 	Non-	 	 	 	 	
 	 	International

	 	Energy

	 	Generation

	 	Other

	 	Total

	
 	 	(In thousands)	
Operations	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Revenues	 	$	13,082	 	 	$	3,869	 	 	$	9,860	 	 	$	(1,160	)	 	$	138,507	 	
Depreciation and amortization	 	 	212	 	 	 	324	 	 	 	497	 	 	 	438	 	 	 	11,808	 	
Reorganization items	 	 	1	 	 	 	—	 	 	 	—	 	 	 	2,192	 	 	 	2,461	 	
Operating Income/(Loss)	 	 	2,071	 	 	 	36	 	 	 	1,514	 	 	 	(3,976	)	 	 	16,095	 	
Minority interest in earnings of consolidated subsidiaries	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(134	)	
Equity in earnings of unconsolidated affiliates	 	 	709	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	13,521	 	
Other income (expense), net	 	 	905	 	 	 	151	 	 	 	77	 	 	 	(1,305	)	 	 	96	 	
Interest expense	 	 	(420	)	 	 	(1	)	 	 	(619	)	 	 	(6,403	)	 	 	(18,902	)	
Income/(Loss) From Continuing Operations Before Income Taxes	 	 	3,265	 	 	 	186	 	 	 	972	 	 	 	(11,684	)	 	 	10,676	 	
Income Tax Expense/(Benefit)	 	 	1,045	 	 	 	—	 	 	 	45	 	 	 	(1,810	)	 	 	(661	)	
Income/(Loss) from Continuing Operations	 	 	2,220	 	 	 	186	 	 	 	927	 	 	 	(9,874	)	 	 	11,337	 	
Income/(Loss) on Discontinued Operations, net of Income Taxes	 	 	(64	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(312	)	
Net Income/(Loss)	 	 	2,156	 	 	 	186	 	 	 	927	 	 	 	(9,874	)	 	 	11,025	 	
Balance Sheet	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Equity investments in affiliates	 	 	196,488	 	 	 	458	 	 	 	—	 	 	 	3,126	 	 	 	737,998	 	
Total Assets	 	$	1,058,072	 	 	$	71,886	 	 	$	334,663	 	 	$	1,120,901	 	 	$	9,244,987	 	
92

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 	 	Reorganized NRG
January 1, 2003 through December 5, 2003	
 	 	Wholesale Power Generation

	
 	 	 	 	 	 	South	 	 	 	 	 	Other North	 	 	
 	 	Northeast

	 	Central

	 	West Coast

	 	America

	 	Australia

	
 	 	(In thousands)	
Operations	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Revenues	 	$	861,452	 	 	$	356,534	 	 	$	23,956	 	 	$	85,388	 	 	$	151,494	 	
Depreciation and amortization	 	 	90,132	 	 	 	33,987	 	 	 	10,750	 	 	 	38,046	 	 	 	17,114	 	
Legal settlement	 	 	—	 	 	 	—	 	 	 	—	 	 	 	4,000	 	 	 	—	 	
Fresh start reporting adjustments	 	 	1,067,783	 	 	 	428,823	 	 	 	106,523	 	 	 	515,166	 	 	 	77,593	 	
Reorganization items	 	 	1,813	 	 	 	28,769	 	 	 	—	 	 	 	41,717	 	 	 	—	 	
Restructuring and impairment charges	 	 	232,170	 	 	 	1,574	 	 	 	—	 	 	 	17,994	 	 	 	5	 	
Operating Income/(Loss)	 	 	(1,330,587	)	 	 	(383,527	)	 	 	(101,366	)	 	 	(577,190	)	 	 	(68,030	)	
Equity in earnings of unconsolidated affiliates	 	 	—	 	 	 	—	 	 	 	102,681	 	 	 	7,260	 	 	 	30,364	 	
Write downs and losses on sales of equity method investments	 	 	—	 	 	 	—	 	 	 	—	 	 	 	12,125	 	 	 	(146,354	)	
Other income (expense), net	 	 	2,308	 	 	 	699	 	 	 	8	 	 	 	2,832	 	 	 	(934	)	
Interest expense	 	 	(69,663	)	 	 	(73,968	)	 	 	—	 	 	 	(92,031	)	 	 	(4,176	)	
Income/(Loss) From Continuing Operations Before Income Taxes	 	 	(1,397,942	)	 	 	(456,796	)	 	 	1,323	 	 	 	(647,004	)	 	 	(189,130	)	
Income Tax Expense/(Benefit)	 	 	—	 	 	 	—	 	 	 	35,746	 	 	 	5,440	 	 	 	15,155	 	
Income/(Loss) from Continuing Operations	 	 	(1,397,942	)	 	 	(456,796	)	 	 	(34,423	)	 	 	(652,444	)	 	 	(204,285	)	
Income/(Loss) on Discontinued Operations, net of Income Taxes	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(279,639	)	 	 	—	 	
Net Income/(Loss)	 	 	(1,397,942	)	 	 	(456,796	)	 	 	(34,423	)	 	 	(932,083	)	 	 	(204,285	)	
Balance Sheet	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Equity investments in affiliates	 	 	1,281	 	 	 	—	 	 	 	309,900	 	 	 	92,965	 	 	 	131,864	 	
Total Assets	 	$	2,264,007	 	 	$	1,328,663	 	 	$	363,691	 	 	$	2,051,790	 	 	$	942,397	 	
93

Table of Contents
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG
January 1, 2003 Through December 5, 2003

	
 	 	All Other

	 	 	 	 	
 	 	Wholesale
Power	 	 	 	 	 	 	 	 	
 	 	Generation

	 	 	 	 	 	 	 	 	
 	 	Other	 	Alternative	 	Non-	 	 	 	 	
 	 	International

	 	Energy

	 	Generation

	 	Other

	 	Total

	
 	 	(In thousands)	
Operations	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Revenues	 	$	137,384	 	 	$	61,098	 	 	$	129,063	 	 	$	(7,755	)	 	$	1,798,614	 	
Depreciation and amortization	 	 	3,550	 	 	 	4,960	 	 	 	11,870	 	 	 	8,792	 	 	 	219,201	 	
Legal settlement	 	 	—	 	 	 	(9,369	)	 	 	—	 	 	 	468,000	 	 	 	462,631	 	
Fresh start reporting adjustments	 	 	(10,676	)	 	 	50,290	 	 	 	181,459	 	 	 	(6,535,597	)	 	 	(4,118,636	)	
Reorganization items	 	 	—	 	 	 	—	 	 	 	—	 	 	 	125,526	 	 	 	197,825	 	
Restructuring and impairment charges	 	 	133	 	 	 	1,067	 	 	 	26	 	 	 	(15,394	)	 	 	237,575	 	
Operating Income/(Loss)	 	 	33,345	 	 	 	(39,894	)	 	 	(150,779	)	 	 	5,890,123	 	 	 	3,272,095	 	
Equity in earnings of unconsolidated affiliates	 	 	31,536	 	 	 	(940	)	 	 	—	 	 	 	—	 	 	 	170,901	 	
Write downs and losses on sales of equity method investments	 	 	3,389	 	 	 	(16,284	)	 	 	—	 	 	 	—	 	 	 	(147,124	)	
Other income (expense), net	 	 	12,647	 	 	 	2,521	 	 	 	75	 	 	 	(948	)	 	 	19,208	 	
Interest expense	 	 	(7,896	)	 	 	(153	)	 	 	(9,805	)	 	 	(72,197	)	 	 	(329,889	)	
Income/(Loss) From Continuing Operations Before Income Taxes	 	 	73,021	 	 	 	(54,750	)	 	 	(160,509	)	 	 	5,816,978	 	 	 	2,985,191	 	
Income Tax Expense/(Benefit)	 	 	16,843	 	 	 	1,597	 	 	 	395	 	 	 	(37,247	)	 	 	37,929	 	
Income/(Loss) from Continuing Operations	 	 	56,178	 	 	 	(56,347	)	 	 	(160,904	)	 	 	5,854,225	 	 	 	2,947,262	 	
Income/(Loss) on Discontinued Operations, net of Income Taxes	 	 	137,819	 	 	 	(23,307	)	 	 	—	 	 	 	(15,690	)	 	 	(180,817	)	
Net Income/(Loss)	 	 	193,997	 	 	 	(79,654	)	 	 	(160,904	)	 	 	5,838,535	 	 	 	2,766,445	 	
Balance Sheet	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Equity investments in affiliates	 	 	194,880	 	 	 	458	 	 	 	—	 	 	 	2,514	 	 	 	733,862	 	
Total Assets	 	$	926,103	 	 	$	73,048	 	 	$	329,597	 	 	$	888,033	 	 	$	9,167,329	 	
94

Table of Contents
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG
Year Ended December 31, 2002	 	 	 	 	
 	 	Wholesale Power Generation

	 	 	 	 	
 	 	 	 	 	 	South	 	 	 	 	 	Other North	 	 	 	 	 	 	
 	 	Northeast

	 	Central

	 	West Coast

	 	America

	 	Australia

	 	 	 	 	
 	 	(In thousands)	 	 	 	 	
Operations	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Revenues	 	$	964,196	 	 	$	388,023	 	 	$	30,796	 	 	$	81,521	 	 	$	170,761	 	 	 	 	 	
Depreciation and amortization	 	 	83,757	 	 	 	35,965	 	 	 	11,243	 	 	 	34,338	 	 	 	14,849	 	 	 	 	 	
Restructuring and impairment charges	 	 	51,130	 	 	 	139,929	 	 	 	—	 	 	 	1,840,652	 	 	 	(16,265	)	 	 	 	 	
Operating Income/(Loss)	 	 	116,189	 	 	 	(46,836	)	 	 	16,795	 	 	 	(1,857,128	)	 	 	14,383	 	 	 	 	 	
Equity in earnings of unconsolidated affiliates	 	 	—	 	 	 	(3,146	)	 	 	24,012	 	 	 	23,287	 	 	 	15,680	 	 	 	 	 	
Write downs and losses on sales of equity method investments	 	 	—	 	 	 	(48,375	)	 	 	—	 	 	 	5,386	 	 	 	(129,190	)	 	 	 	 	
Other income (expense), net	 	 	5,822	 	 	 	922	 	 	 	—	 	 	 	1,359	 	 	 	(1,423	)	 	 	 	 	
Interest expense	 	 	(67,820	)	 	 	(74,940	)	 	 	(160	)	 	 	(88,192	)	 	 	(4,212	)	 	 	 	 	
Income/(Loss) From Continuing Operations Before Income Taxes	 	 	54,191	 	 	 	(172,375	)	 	 	40,647	 	 	 	(1,915,288	)	 	 	(104,762	)	 	 	 	 	
Income Tax Expense/(Benefit)	 	 	—	 	 	 	—	 	 	 	5,843	 	 	 	8,848	 	 	 	(3,033	)	 	 	 	 	
Income/(Loss) from Continuing Operations	 	 	54,191	 	 	 	(172,375	)	 	 	34,804	 	 	 	(1,924,136	)	 	 	(101,729	)	 	 	 	 	
Income/(Loss) on Discontinued Operations, net of Income Taxes	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(93,755	)	 	 	—	 	 	 	 	 	
Net Income/(Loss)	 	 	54,191	 	 	 	(172,375	)	 	 	34,804	 	 	 	(2,017,891	)	 	 	(101,729	)	 	 	 	 	
Balance Sheet	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Equity investments in affiliates	 	 	—	 	 	 	—	 	 	 	398,786	 	 	 	122,007	 	 	 	110,123	 	 	 	 	 	
Total Assets	 	$	2,672,514	 	 	$	1,393,012	 	 	$	442,227	 	 	$	3,028,444	 	 	$	397,895	 	 	 	 	 	

 	 	Reorganized NRG
Year Ended December 31, 2002

	
 	 	All Other

	 	 	 	 	
 	 	Wholesale
Power	 	 	 	 	 	 	 	 	 	 	
 	 	Generation

	 	 	 	 	 	 	 	 	
 	 	Other	 	 	 	 	 	Non-	 	 	 	 	
 	 	International

	 	Alternative Energy

	 	Generation

	 	Other

	 	Total

	
 	 	(In thousands)	
Operations	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Revenues	 	$	108,379	 	 	$	69,286	 	 	$	135,403	 	 	$	(9,816	)	 	$	1,938,549	 	
Depreciation and amortization	 	 	1,242	 	 	 	6,563	 	 	 	12,584	 	 	 	7,608	 	 	 	208,149	 	
Restructuring and impairment charges	 	 	71,108	 	 	 	27,893	 	 	 	31	 	 	 	448,582	 	 	 	2,563,060	 	
Operating Income/(Loss)	 	 	(60,536	)	 	 	(35,505	)	 	 	41,831	 	 	 	(575,030	)	 	 	(2,385,837	)	
Equity in earnings of unconsolidated affiliates	 	 	33,617	 	 	 	(24,454	)	 	 	—	 	 	 	—	 	 	 	68,996	 	
Write downs and losses on sales of equity method investments	 	 	(12,751	)	 	 	(15,542	)	 	 	—	 	 	 	—	 	 	 	(200,472	)	
Other income (expense), net	 	 	10,680	 	 	 	1,502	 	 	 	(142	)	 	 	(7,290	)	 	 	11,430	 	
Interest expense	 	 	(3,030	)	 	 	(3,668	)	 	 	(8,946	)	 	 	(201,216	)	 	 	(452,184	)	
Income/(Loss) From Continuing Operations Before Income Taxes	 	 	(32,020	)	 	 	(77,667	)	 	 	32,743	 	 	 	(783,536	)	 	 	(2,958,067	)	
Income Tax Expense/(Benefit)	 	 	14,982	 	 	 	(16,943	)	 	 	11,654	 	 	 	(188,218	)	 	 	(166,867	)	
Income/(Loss) from Continuing Operations	 	 	(47,002	)	 	 	(60,724	)	 	 	21,089	 	 	 	(595,318	)	 	 	(2,791,200	)	
Income/(Loss) on Discontinued Operations, net of Income Taxes	 	 	(550,877	)	 	 	(28,451	)	 	 	—	 	 	 	1	 	 	 	(673,082	)	
Net Income/(Loss)	 	 	(597,879	)	 	 	(89,175	)	 	 	21,089	 	 	 	(595,317	)	 	 	(3,464,282	)	
Balance Sheet	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Equity investments in affiliates	 	 	201,007	 	 	 	21,942	 	 	 	—	 	 	 	30,398	 	 	 	884,263	 	
Total Assets	 	$	1,973,089	 	 	$	128,010	 	 	$	312,994	 	 	$	548,666	 	 	$	10,896,851	 	
95

Table of Contents
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG
Year Ended December 31, 2001	
 	 	Wholesale Power Generation

	
 	 	 	 	 	 	South	 	 	 	 	 	Other North	 	 	
 	 	Northeast

	 	Central

	 	West Coast

	 	America

	 	Australia

	
 	 	(In thousands)	
Operations	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Revenues	 	$	1,206,611	 	 	$	401,519	 	 	$	23,201	 	 	$	(8,686	)	 	$	213,287	 	
Depreciation and amortization	 	 	63,908	 	 	 	29,427	 	 	 	9,941	 	 	 	1,931	 	 	 	14,570	 	
Operating Income/(Loss)	 	 	340,675	 	 	 	85,931	 	 	 	13,183	 	 	 	(7,947	)	 	 	15,321	 	
Equity in earnings of unconsolidated affiliates	 	 	—	 	 	 	(2,435	)	 	 	162,560	 	 	 	17,353	 	 	 	7,543	 	
Other income (expense), net	 	 	4,760	 	 	 	(190	)	 	 	6,325	 	 	 	2,944	 	 	 	(2,286	)	
Interest expense	 	 	(70,483	)	 	 	(72,101	)	 	 	(64	)	 	 	1,275	 	 	 	(3,856	)	
Income/(Loss) From Continuing Operations Before Income Taxes	 	 	274,952	 	 	 	11,205	 	 	 	182,004	 	 	 	13,625	 	 	 	16,722	 	
Income Tax Expense/(Benefit)	 	 	(4,894	)	 	 	—	 	 	 	70,044	 	 	 	8,998	 	 	 	6,472	 	
Income/(Loss) from Continuing Operations	 	 	279,846	 	 	 	11,205	 	 	 	111,960	 	 	 	4,627	 	 	 	10,250	 	
Income/(Loss) on Discontinued Operations, net of Income Taxes	 	 	—	 	 	 	—	 	 	 	—	 	 	 	9,692	 	 	 	—	 	
Net Income/(Loss)	 	$	279,846	 	 	$	11,205	 	 	$	111,960	 	 	$	14,319	 	 	$	10,250	 	

 	 	Reorganized NRG
Year Ended December 31, 2001

	
 	 	All Other

	 	 	 	 	
 	 	Wholesale
Power	 	 	 	 	 	 	 	 	
 	 	Generation

	 	 	 	 	 	 	 	 	 	
 	 	Other	 	Alternative	 	Non-	 	 	 	 	
 	 	International

	 	Energy

	 	Generation

	 	Other

	 	Total

	
 	 	 	 	 	 	 	 	 	 	(In thousands)	 	 	 	 	 	 	 	 	
Operations	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Revenues	 	$	72,757	 	 	$	53,282	 	 	$	127,898	 	 	$	(4,272	)	 	$	2,085,597	 	
Depreciation and amortization	 	 	417	 	 	 	5,485	 	 	 	13,197	 	 	 	3,207	 	 	 	142,083	 	
Operating Income/(Loss)	 	 	(4,678	)	 	 	(1,255	)	 	 	34,228	 	 	 	(96,339	)	 	 	379,119	 	
Equity in earnings of unconsolidated affiliates	 	 	51,258	 	 	 	(26,236	)	 	 	(11	)	 	 	—	 	 	 	210,032	 	
Other income (expense), net	 	 	8,039	 	 	 	477	 	 	 	214	 	 	 	2,700	 	 	 	22,983	 	
Interest expense	 	 	(4,895	)	 	 	(1,725	)	 	 	(7,021	)	 	 	(205,241	)	 	 	(364,111	)	
Income/(Loss) From Continuing Operations
Before Income Taxes	 	 	49,724	 	 	 	(28,739	)	 	 	27,410	 	 	 	(298,880	)	 	 	248,023	 	
Income Tax Expense/(Benefit)	 	 	6,709	 	 	 	(46,866	)	 	 	10,161	 	 	 	(12,650	)	 	 	37,974	 	
Income/(Loss) from Continuing Operations	 	 	43,015	 	 	 	18,127	 	 	 	17,249	 	 	 	(286,230	)	 	 	210,049	 	
Income/(Loss) on Discontinued Operations,
net of Income Taxes	 	 	44,661	 	 	 	802	 	 	 	—	 	 	 	—	 	 	 	55,155	 	
Net Income/(Loss)	 	$	87,676	 	 	$	18,929	 	 	$	17,249	 	 	$	(286,230	)	 	$	265,204	 	
Note 21 — Income Taxes

     For the year ended December 31, 2002 and the period January 1, 2003 through December 5, 2003, income taxes have been recorded on the basis that Xcel Energy will not be including us in its consolidated federal income tax return following Xcel Energy’s acquisition of our public shares on June 3, 2002. Since our U.S. subsidiaries and we will not be included in the Xcel Energy consolidated federal income tax return for the period January 1, 2003 through December 5, 2003, we and each of our U.S. subsidiaries that is classified as a corporation for U.S. income tax purposes must file separate federal income tax returns.

     Following our emergence from bankruptcy on December 5, 2003, we and our U.S. subsidiaries will file a consolidated federal income tax return. We have reviewed the requirements for reconsolidation and believe we satisfy them.

     The provision (benefit) for income taxes consists of the following:

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Table of Contents
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor Company

	 	Reorganized NRG

	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	For the Period	 	For the Period	 	 	 	 	 	 	 	 	 	 	 	
 	 	Year Ended December 31,

	 	January 1 -
December 5,	 	December 6 -
December 31,	 	 	 	 	 	 	 	 	 	 	 	
 	 	2001

	 	2002

	 	2003

	 	2003

	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	(In thousands)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
U.S.	 	$	28,792	 	 	$	10,409	 	 	$	2,231	 	 	$	(1,513	)	 	 	 	 	 	 	 	 	 	 	 	
Foreign	 	 	10,025	 	 	 	17,160	 	 	 	15,630	 	 	 	1,184	 	 	 	 	 	 	 	 	 	 	 	 	

	 	 	

	 	 	

	 	 	

	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	38,817	 	 	 	27,569	 	 	 	17,861	 	 	 	(329	)	 	 	 	 	 	 	 	 	 	 	 	
Deferred	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
U.S.	 	 	31,820	 	 	 	(191,447	)	 	 	3,292	 	 	 	59	 	 	 	 	 	 	 	 	 	 	 	 	
Foreign	 	 	4,529	 	 	 	(2,989	)	 	 	16,776	 	 	 	(391	)	 	 	 	 	 	 	 	 	 	 	 	

	 	 	

	 	 	

	 	 	

	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	36,349	 	 	 	(194,436	)	 	 	20,068	 	 	 	(332	)	 	 	 	 	 	 	 	 	 	 	 	
Tax credits recognized	 	 	(37,192	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	

	 	 	

	 	 	

	 	 	

	 	 	 	 	 	 	 	 	 	 	 	 	
Total income tax (benefit)	 	$	37,974	 	 	$	(166,867	)	 	$	37,929	 	 	$	(661	)	 	 	 	 	 	 	 	 	 	 	 	

	 	 	

	 	 	

	 	 	

	 	 	 	 	 	 	 	 	 	 	 	 	
Effective tax rate	 	 	15.3	%	 	 	5.6	%	 	 	1.3	%	 	 	(6.2	)%	 	 	 	 	 	 	 	 	 	 	 	
     The pre-tax income (loss) from U.S. and foreign entities was as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor Company

	 	Reorganized NRG

	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	For the Period	 	For the Period	 	 	 	 	 	 	 	 	 	 	 	
 	 	Year Ended December 31,

	 	January 1 -
December 5,	 	December 6 -
December 31,	 	 	 	 	 	 	 	 	 	 	 	
 	 	2001

	 	2002

	 	2003

	 	2003

	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	(In thousands)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
U.S.	 	$	181,560	 	 	$	(2,821,285	)	 	$	3,101,301	 	 	$	6,760	 	 	 	 	 	 	 	 	 	 	 	 	
Foreign	 	 	66,463	 	 	 	(136,782	)	 	 	(116,110	)	 	 	3,916	 	 	 	 	 	 	 	 	 	 	 	 	

	 	 	

	 	 	

	 	 	

	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	$	248,023	 	 	$	(2,958,067	)	 	$	2,985,191	 	 	$	10,676	 	 	 	 	 	 	 	 	 	 	 	 	

	 	 	

	 	 	

	 	 	

	 	 	 	 	 	 	 	 	 	 	 	 	
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     The components of the net deferred income tax liability were:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor	 	 	
 	 	Company

	 	Reorganized NRG

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2002

	 	2003

	 	2003

	
 	 	 	 	 	 	(In thousands)	 	 	 	 	
Deferred tax liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	
Difference between book and tax basis of property	 	$	368,712	 	 	$	—	 	 	$	—	 	
Discount/premium on notes	 	 	—	 	 	 	34,602	 	 	 	34,136	 	
Emissions credits	 	 	—	 	 	 	147,811	 	 	 	147,811	 	
Net unrealized gains on mark to market transactions	 	 	37,800	 	 	 	14,868	 	 	 	12,461	 	
Other	 	 	9,167	 	 	 	988	 	 	 	988	 	

 	 	 	 	

 	 	 	 	

 	 	
Total deferred tax liabilities	 	$	415,679	 	 	$	198,269	 	 	$	195,396	 	
Deferred tax assets:	 	 	 	 	 	 	 	 	 	 	 	 	
Deferred compensation, accrued vacation and other reserves	 	 	53,907	 	 	 	55,734	 	 	 	55,063	 	
Development costs	 	 	11,079	 	 	 	3,017	 	 	 	2,999	 	
Foreign tax loss carryforwards	 	 	231,668	 	 	 	341,991	 	 	 	342,017	 	
Differences between book and tax basis of contracts	 	 	24,155	 	 	 	222,655	 	 	 	199,940	 	
Difference between book and tax basis of property	 	 	702,905	 	 	 	72,820	 	 	 	79,070	 	
Intangibles amortization (other than goodwill)	 	 	—	 	 	 	13,191	 	 	 	13,053	 	
Restructuring costs	 	 	—	 	 	 	20,462	 	 	 	20,468	 	
U.S. tax loss carry forwards	 	 	456,460	 	 	 	389,020	 	 	 	402,940	 	
Investments in projects	 	 	7,967	 	 	 	164,343	 	 	 	159,370	 	
Other	 	 	22,953	 	 	 	11,964	 	 	 	13,934	 	

 	 	 	 	

 	 	 	 	

 	 	
Total deferred tax assets (before valuation allowance)	 	 	1,511,094	 	 	 	1,295,197	 	 	 	1,288,854	 	
Valuation allowance	 	 	(1,170,301	)	 	 	(1,241,616	)	 	 	(1,241,101	)	

 	 	 	 	

 	 	 	 	

 	 	
Net deferred tax assets	 	 	340,793	 	 	 	53,581	 	 	 	47,753	 	

 	 	 	 	

 	 	 	 	

 	 	
Net deferred tax liability	 	$	74,886	 	 	$	144,688	 	 	$	147,643	 	

 	 	 	 	

 	 	 	 	

 	 	
     The net deferred tax liability consists of:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor	 	 	
 	 	Company

	 	Reorganized NRG

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2002

	 	2003

	 	2003

	
 	 	 	 	 	 	(In thousands)	 	 	 	 	
Current deferred tax asset	 	$	—	 	 	$	—	 	 	$	1,850	 	
Non-current deferred tax liability	 	 	74,886	 	 	 	144,688	 	 	 	149,493	 	

 	 	 	 	

 	 	 	 	

 	 	
Net deferred tax liability	 	$	74,886	 	 	$	144,688	 	 	$	147,643	 	

 	 	 	 	

 	 	 	 	

 	 	
     As of December 31, 2003, we provided a valuation allowance of approximately $556.6 million to account for potential limitations on utilization of U.S. and foreign net operating loss carryforwards. If unused, the U.S. net operating loss carryforward of $1.0 billion generated in 2002 and 2003, will expire by 2023. Net operating loss carryforwards for foreign tax purposes have no expiration date. We also have a valuation allowance for other U.S. and foreign deferred income tax assets of approximately $684.5 million as of December 31, 2003.

     We assessed the likelihood that a substantial portion of our deferred tax assets relating to the net operating loss carryforwards would not be realized. This assessment included consideration of positive and negative factors, including our current financial position and results of operations, projected future taxable income, including projected operating and capital gains, and available tax planning strategies. As a result of such assessment, we determined that it was more likely than not that the deferred tax assets related to our domestic net operating loss carryforwards would not be realized. As noted above, a full valuation allowance was recorded against the net deferred tax assets including net operating loss carryforwards. We also determined that it is more likely than not that a substantial portion of the net operating loss generated in 2002 and 2003 could be determined to be capital in nature. Given that capital losses are of a different character than ordinary losses the likelihood of capital losses expiring unutilized is greater than that of ordinary net operating losses.

     In addition, the conversion of ordinary losses to capital losses, to the extent that amount exceeds our existing net operating loss, results in a corresponding reduction to the tax basis of our fixed assets. The consequence of which is a reduction to expected tax depreciation expense in future years.

     As of December 5, 2003, we provided a valuation allowance of approximately $542.0 million to account for potential limitations on utilization of U.S. and foreign net operating loss carryforwards compared to a valuation allowance of $494.5 million for the same period in 2002. We also provided a valuation allowance for other U.S. and foreign deferred income tax assets of approximately $699.7 million for the period ended December 5, 2003 compared to $578.7 million for the same period in 2002.

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The effective income tax rates of continuing operations for the years ended December 31, 2001, 2002 and 2003 differ from the statutory federal income tax rate of 35% as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor Company

	 	Reorganized NRG

	
 	 	Year Ended December 31,	 	For the Period	 	For the Period	

	 	January 1 - December 5,	 	December 6 - December 31,	
 	 	2001

	 	2002

	 	2003

	 	2003

	
Income/(Loss) From Continuing Operations Before Income Taxes	 	$	248,023	 	 	 	 	 	 	 	($2,958,067	)	 	 	 	 	 	$	2,985,191	 	 	 	 	 	 	$	10,676	 	 	 	 	 	
Tax at 35%	 	 	86,808	 	 	 	35.0	%	 	 	(1,035,323	)	 	 	35.0	%	 	 	1,044,817	 	 	 	35.0	%	 	 	3,737	 	 	 	35.0	%	
State taxes, (net of federal benefit)	 	 	7,428	 	 	 	3.0	%	 	 	(167,405	)	 	 	5.7	%	 	 	254,112	 	 	 	8.5	%	 	 	(1,834	)	 	 	(17.2	)%	
Foreign operations	 	 	(29,125	)	 	 	(11.7	)%	 	 	(18,522	)	 	 	0.6	%	 	 	15,001	 	 	 	0.5	%	 	 	(1,265	)	 	 	(11.8	)%	
Fresh Start accounting adjustments	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(1,383,334	)	 	 	(46.3	)%	 	 	—	 	 	 	—	 	
Tax credits	 	 	(37,192	)	 	 	(15.0	)%	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Valuation allowance	 	 	21,389	 	 	 	8.6	%	 	 	1,006,540	 	 	 	(34.0	)%	 	 	71,315	 	 	 	2.3	%	 	 	(515	)	 	 	(4.8	)%	
Change in tax rate	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	36,018	 	 	 	1.3	%	 	 	—	 	 	 	—	 	
Permanent differences, reserves, other	 	 	(11,334	)	 	 	(4.6	)%	 	 	47,843	 	 	 	(1.7	)%	 	 	—	 	 	 	—	 	 	 	(784	)	 	 	(7.4	)%	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Income Tax Expense/(Benefit)	 	$	37,974	 	 	 	15.3	%	 	 	($166,867	)	 	 	5.6	%	 	$	37,929	 	 	 	1.3	%	 	 	($661	)	 	 	(6.2	)%	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
     Income tax benefit/expense for the period December 6, 2003 through December 31, 2003 was a tax benefit of $0.7 million which includes $1.5 million benefit and $0.8 million expense of U.S. and foreign taxes, respectively. The U.S. tax benefit recorded for this period is the result of a state tax refund received from Xcel Energy pursuant to the tax matters agreement. The foreign tax expense for the period is due to earnings in the foreign jurisdictions.

     The income tax benefit/expense for the period January 1, 2003 through December 5, 2003 was a tax expense of $37.9 million compared to a tax benefit of $166.9 million for the year ended December 31, 2002. During 2003, an additional valuation allowance of $33 million was recorded against the deferred tax assets of NRG West Coast as a result of its conversion from a corporation to a single member limited liability company (a disregarded entity for federal income tax purposes). Subsequent to the conversion, NRG West Coast will no longer be taxed as an entity separate from us.

     As of December 31, 2003, our management intends to indefinitely reinvest the earnings from our foreign operations. Accordingly, U.S. income taxes and foreign withholding taxes were not provided on the earnings from our foreign subsidiaries. As of December 31, 2003, December 5, 2003, and December 31, 2002 no U.S. income tax benefit was provided on the cumulative amount of losses from our foreign subsidiaries of $387.5 million, $438.4 million, and $341.7 million, respectively.

Note 22 — Related Party Transactions

     While we were an indirect, wholly owned subsidiary of Xcel Energy, we became an independent public company upon our emergence from bankruptcy on December 5, 2003. We no longer have any material affiliation or relationship with Xcel Energy. Prior to December 5, 2003, we had entered into material transactions and agreements with Xcel Energy. Certain material agreements and transactions existing during 2003 between NRG Energy and Xcel Energy are described below.

Operating Agreements

     We have two agreements with Xcel Energy for the purchase of thermal energy. Under the terms of the agreements, Xcel Energy charges us for certain costs (fuel, labor, plant maintenance, and auxiliary power) incurred by Xcel Energy to produce the thermal energy. We paid Xcel Energy $7.1 million, $8.2 million and $9.6 million in 2001, 2002 and the period January 1, 2003 to December 5, 2003, respectively, under these agreements. One of these agreements expired on December 31, 2002 and the other expires on December 31, 2006.

     We have a renewable 10-year agreement with Xcel Energy, expiring on December 31, 2006, whereby Xcel Energy agreed to purchase refuse-derived fuel for use in certain of its boilers and we agree to pay Xcel Energy a burn incentive. Under this agreement, we received $1.6 million, $1.2 million and $1.4 million from Xcel Energy, and paid $2.8 million, $3.3 million and $3.9 million to Xcel Energy in 2001, 2002 and the period January 1, 2003 to December 5, 2003, respectively.

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Administrative Services and Other Costs

     We had an administrative services agreement in place with Xcel Energy. Under this agreement we reimbursed Xcel Energy for certain overhead and administrative costs, including benefits administration, engineering support, accounting, and other shared services as requested by us. In addition, our employees participated in certain employee benefit plans of Xcel Energy as discussed in Note 23. We reimbursed Xcel Energy in the amounts of $12.2 million, $21.2 million and $7.3 million during 2001, 2002 and the period January 1, 2003 to December 5, 2003, respectively, under this agreement. This agreement was terminated December 5, 2003.

Natural Gas Marketing and Trading Agreement

     We had an agreement with e prime, a wholly owned subsidiary of Xcel Energy, under which e prime provided natural gas marketing and trading from time to time at our request. We paid $19.2 million to e prime in 2002 related to these services. This agreement was terminated by e prime on December 12, 2002 and a termination charge of $0.3 million was paid in the period January 1, 2003 to December 5, 2003.

Amounts owed to Xcel Energy

     Included in accounts payable affiliate is approximately $42.9 million of amounts owed to Xcel Energy at December 31, 2002. While we were an indirect, wholly owned subsidiary of Xcel Energy, we became an independent public company upon our emergence from bankruptcy on December 5, 2003. As part of our restructuring, amounts owed to Xcel Energy were forgiven and replaced by a $10.0 million promissory note, which was outstanding as of December 6, 2003 and December 31, 2003.

Xcel Settlement Agreement

     Included in the company’s balance sheet is a $640.0 million receivable from Xcel Energy. Under the terms of the settlement agreement, payments were to be made in three installments. As of December 6, 2003 and December 31, 2003, the balance was $640.0 million.

Note 23 — Benefit Plans and Other Postretirement Benefits

Reorganized NRG

     Substantially all of our employees participate in defined benefit pension plans. We have initiated a new NRG Energy noncontributory, defined benefit pension plan effective January 1, 2004, with credit for service from December 5, 2003. On December 5, 2003, we recorded a liability of approximately $48.0 million to record our accumulated benefit obligations at fair value. As of December 31, 2003, there were no plan assets related to the plans assumed from Xcel Energy. We have chosen the plan Trustee and are in the preliminary stages of defining the investment strategies for this plan.

     In addition, we provide postretirement health and welfare benefits (health care and death benefits) for certain groups of our 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.

Cash Flow

     We expect to contribute approximately $2.0 million to our NRG pension plan and our postretirement health and welfare plan in 2004.

NRG Flinders Retirement Plan

     Employees of NRG Flinders, a wholly owned subsidiary of NRG Energy, are members of the multiemployer Electricity Industry Superannuation Schemes, or “EISS.” Members of the EISS make contributions from their salary and the EISS Actuary makes an assessment of our liability. As a result of adopting Fresh Start we recorded a liability of approximately $13.8 million at December 5, 2003, to record our accumulated benefit obligation plan assets on the balance sheet at fair value. The balance sheet includes a liability related to the Flinders retirement plan of $12.3 million, $13.8 million and $13.7 million at December 31, 2002, December 5, 2003 and

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December 31, 2003, respectively. NRG Flinders contributed $5.8 million, $4.5 million and $0 for the year ended December 31, 2002, the period January 1 through December 5, 2003 and the period December 6 through December 31, 2003, respectively.

     The Superannuation Board is responsible for the investment of Scheme assets. The assets may be invested in government securities, shares, property and a variety of other securities and the Board may appoint professional investment managers to invest all or part of the assets on its behalf.

NRG Pension and Postretirement Medical Plans

Components of Net Periodic Benefit Cost

     The net annual periodic pension cost related to all of our plans, include the following components:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Pension Benefits

	 	Other Benefits

	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	Reorganized	 	 	 	 	 	 	 	 	 	 	 	 	 	Reorganized	
 	 	Predecessor Company

	 	NRG

	 	Predecessor Company

	 	NRG

	
 	 	 	 	 	 	 	 	 	 	For the	 	For the	 	 	 	 	 	 	 	 	 	For the	 	For the	
 	 	Year Ended	 	Period	 	Period	 	Year Ended	 	Period	 	Period	
 	 	December 31,

	 	January 1 -
December 5,	 	December 6 -
December 31,	 	December 31,

	 	January 1 -
December 5,	 	December 6 -
December 31,	
 	 	2001

	 	2002

	 	2003

	 	2003

	 	2001

	 	2002

	 	2003

	 	2003

	
 	 	(In thousands)	 	In thousands)	
Service cost benefits earned	 	$	—	 	 	$	—	 	 	$	—	 	 	$	800	 	 	$	902	 	 	$	1,206	 	 	$	1,220	 	 	$	130	 	
Interest cost on benefit obligation	 	 	—	 	 	 	—	 	 	 	—	 	 	 	205	 	 	 	1,402	 	 	 	1,831	 	 	 	1,900	 	 	 	180	 	
Amortization of prior service cost	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(25	)	 	 	(24	)	 	 	(22	)	 	 	—	 	
Expected return on plan assets	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Recognized actuarial (gain)/loss	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	 	 	 	(56	)	 	 	5	 	 	 	178	 	 	 	—	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Net periodic benefit cost	 	$	—	 	 	$	—	 	 	$	—	 	 	$	1,005	 	 	$	2,223	 	 	$	3,018	 	 	$	3,276	 	 	$	310	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
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Reconciliation of Funded Status

     A comparison of the pension benefit obligation and pension assets at December 6, 2003 and December 31, 2003 for all of our plans on a combined basis is as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Pension Benefits

	 	Other Benefits

	
Reorganized NRG

	 	December 6, 2003

	 	December 31, 2003

	 	December 6, 2003

	 	December 31, 2003

	
 	 	 	 	 	 	(In thousands)	 	 	 	 	
Benefit obligation at Jan. 1/Dec. 6	 	$	—	 	 	$	47,950	 	 	$	31,584	 	 	$	41,900	 	
Service cost	 	 	—	 	 	 	800	 	 	 	1,220	 	 	 	130	 	
Interest cost	 	 	—	 	 	 	205	 	 	 	1,900	 	 	 	180	 	
Plan initiation	 	$	47,950	 	 	 	—	 	 	 	—	 	 	 	—	 	
Employee contributions	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Plan amendments	 	 	—	 	 	 	—	 	 	 	2,100	 	 	 	—	 	
Actuarial (gain)/loss	 	 	—	 	 	 	—	 	 	 	5,396	 	 	 	—	 	
Benefit payments	 	 	—	 	 	 	—	 	 	 	(300	)	 	 	(40	)	
Foreign currency translation	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Benefit obligation at Dec. 5/ Dec. 31	 	$	47,950	 	 	$	48,955	 	 	$	41,900	 	 	$	42,170	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Fair value of plan assets at Jan. 1/ Dec 6	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	
Actual return on plan assets	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Employee contributions	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Employer contributions	 	 	—	 	 	 	—	 	 	 	300	 	 	 	40	 	
Benefit payments	 	 	—	 	 	 	—	 	 	 	(300	)	 	 	(40	)	
Foreign currency translation	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Fair value of plan assets at Dec. 5/ Dec. 31	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Funded status at Dec. 5/Dec. 31 — excess of obligation over assets	 	$	(47,950	)	 	$	(48,955	)	 	$	(41,900	)	 	$	(42,170	)	
Unrecognized prior service cost	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Unrecognized net (gain) loss	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Accrued benefit liability recognized on the consolidated balance sheet at Dec. 5/Dec. 31	 	$	(47,950	)	 	$	(48,955	)	 	$	(41,900	)	 	$	(42,170	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
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     A comparison of the pension benefit obligation and pension assets at December 31, 2002 for all of our plans on a combined basis is as follows:
 	 	 	 	 	 	 	 	 	
 	 	Pension Benefits	 	Other Benefits	
Predecessor Company

	 	2002

	 	2002

	
 	 	(In thousands)	
Benefit obligation at Jan. 1	 	$	—	 	 	$	24,602	 	
Service cost	 	 	—	 	 	 	1,206	 	
Interest cost	 	 	—	 	 	 	1,831	 	
Plan initiation	 	 	—	 	 	 	—	 	
Employee contributions	 	 	—	 	 	 	—	 	
Plan amendments	 	 	—	 	 	 	—	 	
Actuarial (gain)/loss	 	 	—	 	 	 	4,101	 	
Acquisitions (transfers)	 	 	—	 	 	 	—	 	
Benefit payments	 	 	—	 	 	 	(156	)	
Foreign currency translation	 	 	—	 	 	 	—	 	

 	 	 	 	

 	 	
Benefit obligation at Dec. 31	 	$	—	 	 	$	31,584	 	

 	 	 	 	

 	 	
Fair value of plan assets at Jan. 1	 	$	—	 	 	$	—	 	
Actual return on plan assets	 	 	—	 	 	 	—	 	
Employee contributions	 	 	—	 	 	 	—	 	
Employer contributions	 	 	—	 	 	 	156	 	
Benefit payments	 	 	—	 	 	 	(156	)	
Foreign currency translation	 	 	—	 	 	 	—	 	

 	 	 	 	

 	 	
Fair value of plan assets at Dec. 31	 	$	—	 	 	$	—	 	

 	 	 	 	

 	 	
Funded status at Dec. 31 — excess of obligation over assets	 	$	—	 	 	$	(31,584	)	
Unrecognized prior service cost	 	 	—	 	 	 	(229	)	
Unrecognized net (gain) loss	 	 	—	 	 	 	5,967	 	

 	 	 	 	

 	 	
Accrued benefit liability recognized on the consolidated balance sheet at Dec. 31	 	$	—	 	 	$	(25,846	)	

 	 	 	 	

 	 	
     The following table presents significant assumptions used:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Pension	 	 	
 	 	Benefits

	 	Other Benefits

	
 	 	2002

	 	2003

	 	2002

	 	2003

	
Weighted-average assumption as of December 31,	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Discount rate	 	 	—	 	 	 	6.00	%	 	 	6.75	%	 	 	6.00	%	
Expected return on plan assets	 	 	—	 	 	NA*	 	 	—	 	 	 	—	 	
Rate of compensation increase	 	 	—	 	 	 	4.50	 	 	 	3.50-4.50	 	 	 	4.50	 	

*	 	We did not determine an expected return on plan assets for the NRG pension plan, as there are no plan assets at December 31, 2003.	
     Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effect (in thousands):
 	 	 	 	 	 	 	 	 	
 	 	1-Percentage-	 	1-Percentage-	
 	 	Point Increase

	 	Point Decrease

	
Effect on total of service and interest cost components	 	$	440	 	 	$	(400	)	
Effect on postretirement benefit obligation	 	 	4,175	 	 	 	(4,048	)	
Defined Contribution Plans

     Our employees have also been eligible to participate in defined contribution 401(K) plans. Our contributions to these plans were approximately $3.2 million, $4.6 million and $3.8 million in 2001, 2002 and 2003, respectively.

Predecessor Company

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     Prior to December 5, 2003, all eligible employees participated in Xcel Energy’s multiemployer noncontributory, defined benefit pension plan, which was formerly sponsored by NSP. We sponsored two defined benefit plans that were merged into Xcel Energy’s plan as of June 30, 2002. Benefits are generally based on a combination of an employee’s years of service and earnings. Some formulas also take into account Social Security benefits. Plan assets principally consisted of the common stock of public companies, corporate bonds and U.S. government securities.

     Prior to December 5, 2003, certain former NRG Energy retirees were covered under the legacy Xcel Energy plan, which was terminated for non-bargaining employees retiring after 1998 and for bargaining employees retiring after 1999.

     As a result of our emergence from bankruptcy on December 5, 2003, we are no longer owned by or affiliated with Xcel Energy and our employees are no longer participants of the Xcel Energy plans.

Participation in Xcel Energy, Inc. Pension Plan and Postretirement Medical Plan

     We did not make contributions to the Xcel Energy pension plan and postretirement plan in 2001, 2002 or 2003. The balance sheet includes a liability related to the Xcel Energy Pension Plan of $1.7 million for 2002. The balance sheet also includes a liability related to the Xcel Energy Postretirement Medical Plan of $2.2 million for 2002. As of December 31, 2003, there are no liabilities recorded related to the Xcel Energy plans. The liabilities associated with these plans were settled as part of the NRG plan of reorganization. The net annual periodic cost (credit) related to our portion of the Xcel Energy pension plan and postretirement plans totaled $(8.9) million, $(8.9) million and $0.2 million for 2001, 2002 and 2003, respectively.

     Prior to December 5, 2003, certain employees also participated in Xcel Energy’s noncontributory defined benefit supplemental retirement income plan. This plan is for the benefit of certain qualifying executive personnel. Benefits for this unfunded plan are paid out of operating cash flows. The balance sheet includes a liability related to this plan of $3.2 million and $0.4 million as of December 31, 2002 and 2003, respectively.

2003 Medicare Legislation

     On December 8, 2003, President Bush signed into law the Medicare Prescription Drug Improvement and Modernization Act of 2003, or “the Act.” The Act expanded Medicare to include, for the first time, coverage for prescription drugs. This coverage is generally effective January 1, 2006. The execution of this new legislation had no significant impact on our statement of financial position or results of operation as of December 31, 2003 and for the period December 6, 2003 through December 31, 2003. Any future impact will be recognized as incurred.

Note 24 — Commitments and Contingencies

Operating Lease Commitments

     We lease certain of our facilities and equipment under operating leases, some of which include escalation clauses, expiring on various dates through 2023. Rental expense under these operating leases was $10.0 million, and $13.4 million for the years ended December 31, 2001 and 2002, respectively and $12.2 million and $0.7 million for the periods January 1, 2003 through December 5, 2003 and December 6, 2003 through December 31, 2003, respectively. Future minimum lease commitments under these leases for the years ending after December 31, 2003 are as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Continuing	 	Discontinued	 	 	
 	 	Operations

	 	Operations

	 	Total

	
 	 	(In thousands)	
2004	 	$	8,760	 	 	$	464	 	 	$	9,224	 	
2005	 	 	7,770	 	 	 	363	 	 	 	8,133	 	
2006	 	 	7,029	 	 	 	362	 	 	 	7,391	 	
2007	 	 	3,971	 	 	 	343	 	 	 	4,314	 	
2008	 	 	3,161	 	 	 	365	 	 	 	3,526	 	
Thereafter	 	 	14,934	 	 	 	—	 	 	 	14,934	 	

 	 	 	 	

 	 	 	 	

 	 	
Total	 	$	45,625	 	 	$	1,897	 	 	$	47,522	 	

 	 	 	 	

 	 	 	 	

 	 	
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Capital Commitments

     We anticipate funding our ongoing capital requirements through committed debt facilities, operating cash flows, and existing cash. Our capital expenditure program is subject to continuing review and modification. The timing and actual amount of expenditures may differ significantly based upon plant operating history, unexpected plant outages, and changes in the regulatory environment, and the availability of cash.

NRG FinCo Settlement

     In May 2001, our wholly-owned subsidiary, NRG FinCo, entered into a $2.0 billion revolving credit facility. The facility was established to finance the acquisition, development and construction of power generating plants located in the United States and to finance the acquisition of turbines for such facilities. The facility provided for borrowings of base rate loans and Eurocurrency loans and was secured by mortgages and security agreements in respect of the assets of the projects financed under the facility, pledges of the equity interests in the subsidiaries or affiliates of the borrower that own such projects, and by guaranties from each such subsidiary or affiliate. The NRG FinCo secured revolver was initially scheduled to mature on May 8, 2006; however, due to defaults hereunder by NRG FinCo and applicable guarantors, the lenders accelerated all outstanding obligations on November 6, 2002. As of our emergence, $1.1 billion was outstanding under the facility, and there was an aggregate of approximately $58 million of accrued but unpaid interest and commitment fees. Of this, $842.0 million was allowed in unsecured claims under NRG plan of reorganization, and was settled at the time of our emergence. The remaining balance will be satisfied when the NRG FinCo lenders exercise their perfected security interests in our Nelson, Audrain and Pike projects. These project companies hold assets with estimated fair market values of approximately $55.2 million, $172.0 million and $48.0 million, respectively. The amount of $55.2 million for Nelson consists of a partially completed project. Since the Nelson entity is currently in bankruptcy, we are recording the entity as a cost method investment with the fair value of the assets equaling the fair value of the obligation to the NRG FinCo lenders. The Audrain project cost of $172.0 million represents the fair value of the operating assets consisting of property plant and equipment. An offsetting liability of $172.0 million was recorded as of Fresh Start to the NRG FinCo lenders. The Pike entity holds a turbine with an estimated fair value of approximately $48.0 million. Additionally, we also recorded an equal liability of $48.0 million to the NRG FinCo lenders. The obligations of Audrain and Pike totaling $220.0 million is reflected on the balance sheet as other bankruptcy settlement. We are in the process of marketing for sale each of the Audrain, Pike, and Nelson projects on behalf of the NRG FinCo lenders. The NRG FinCo lenders have authority under their perfected security interest to accept or reject all offers. As a result these entities are not reflected as a discontinued operations. We believe we have no additional risk of loss related to these entities.

     In connection with our acquisition of the Audrain facilities, we have recognized a capital lease on its balance sheet within long-term debt in the amount of $239.9 million, as of December 31, 2003 and 2002. The capital lease obligation is recorded at the net present value of the minimum lease obligation payable. The lease terminates in May 2023. During the term of the lease only interest payments are due, no principal is due until the end of the lease. In addition, we have recorded in notes receivable, an amount of approximately $239.9 million, which represents its investment in the bonds that the county of Audrain issued to finance the project. During February 2004, we received a notice of a waiver of a $24.0 million interest payment due on the capital lease obligation. In connection with the transfer of the security in the Audrain projects to NRG FinCo Lenders, the Audrain entity will be liquidated resulting in the termination of the lease obligation and the note receivable.

Environmental Regulatory Matters

     The construction and operation of power projects are subject to stringent environmental and safety protection and land use laws and regulation in the United States. These laws and regulations generally require lengthy and complex processes to obtain licenses, permits and approvals from federal, state and local agencies. If such laws and regulations become more stringent and our facilities are not exempted from coverage, we could be required to make extensive modifications to further reduce potential environmental impacts.

     Under various federal, state and local environmental laws and regulations, a current or previous owner or operator of any facility, including an electric generating 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, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended by the Superfund Amendments and Reauthorization Act of 1986, impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and courts have interpreted liability under such laws to be strict (without fault) and joint and several. The cost of investigation, remediation or removal of any hazardous or toxic substances or petroleum products could be substantial. Although we have been involved in on-site contamination matters, to date, we have not been named as a potentially responsible party with respect to any off-site waste disposal matter.

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     We strive to exceed the standards of compliance with applicable environmental and safety regulations. Nonetheless, we expect that future liability under or compliance with environmental and safety requirements could have a material effect on our operations or competitive position. It is not possible at this time to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of possible changes to environmental and safety regulations, regulatory interpretations or enforcement policies. 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 our operations.

     As part of acquiring existing generating assets, we have 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 governmental priorities or (e) selection of a less expensive compliance option than originally envisioned.

West Coast Region

     The Asset Purchase Agreements for the Long Beach, El Segundo, Encina, and San Diego gas turbine generating facilities provide that Southern California Edison and San Diego Gas & Electric retain liability and indemnify us for existing soil and groundwater contamination that exceeds remedial thresholds in place at the time of closing. Along with our business partner, we conducted Phase I and Phase II Environmental Site Assessments at each of these sites for purposes of identifying such existing contamination and provided the results to the sellers. San Diego Gas & Electric has undertaken corrective actions at the Encina and San Diego gas turbine generating sites related to issues identified in these assessments, although final government agency approval to certify completeness of the corrective action has not yet been obtained. While spills and releases of various substances have occurred at many sites since establishing the historical baseline, all but one has been remediated in accordance with existing laws. An unquantified amount of soil contaminated by lubricating oil that leaked from underground piping at the El Segundo Generating Station has been allowed by the Regional Water Quality Control Board to remain under the foundation of the Unit I powerhouse until the building is demolished.

     Our affiliates have incurred capital expenditures at the Encina Generating Station to install Selective Catalytic Reduction, or “SCR” emission control technology on all five generating units. Units 4 & 5 were retrofitted with SCRs during 2002; while Units 1, 2, and 3 were retrofitted with SCRs in 2003. The cost to retrofit all five units totaled approximately $42 million.

Eastern Region

     Coal ash is produced as a by-product of coal combustion at the Dunkirk, Huntley, and Somerset Generating Stations. We attempt to direct its coal ash to beneficial uses. Even so, significant amounts of ash are landfilled at on and off-site locations. At Dunkirk and Huntley, ash is disposed at landfills owned and operated by us. No material liabilities outside the costs associated with closure, post-closure care and monitoring are expected at these facilities. We maintain financial assurance to cover costs associated with closure, post-closure care and monitoring activities. In the past, we have provided financial assurance via financial test and corporate guarantee. As a result of our debt restructuring process, we were required to re-establish financial assurance via an instrument requiring complete collateralization of closure and post-closure-related costs, such costs currently estimated at approximately $5.9 million. We provided such financial assurance via a trust fund established in this amount on April 30, 2003.

     We must also maintain financial assurance for closing interim status RCRA facilities at the Devon, Middletown, Montville and Norwalk Harbor Generating Stations. Previously, we have provided financial assurance via financial test. As a result of our debt restructuring process, we were required to re-establish financial assurance via an instrument requiring complete collateralization of closure and post-closure-related costs, such costs currently estimated at approximately $1.5 million. We provided such financial assurance via a trust fund established in this amount on April 30, 2003.

     Historical clean-up liabilities were inherited as a part of acquiring the Somerset, Devon, Middletown, Montville, Norwalk Harbor, Arthur Kill and Astoria Generating Stations. We have recently satisfied clean-up obligations associated with the Ledge Road property (inherited as part of the Somerset acquisition). Site contamination liabilities arising under the Connecticut Transfer Act at the Devon, Middletown, Montville and Norwalk Harbor Stations have been identified and are currently being refined as part of on-going site investigations. We do not expect to incur material costs associated with completing the investigations at these Stations or future work to cover and monitor ash management areas pursuant to the Connecticut requirements. Remedial liabilities at the Arthur Kill Generating Station have been established in discussions between us and the New York State DEC and are expected to cost on the order of $1.0 million. Remedial investigations are on-going at the Astoria Generating Station. At this time, our long-term cleanup liability at this site is not expected to exceed $1.5 million.

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     We estimate that we will incur total environmental capital expenditures of $79.7 million during 2004 through 2008 for the facilities in New York, Connecticut and Massachusetts. These expenditures will be primarily related to changes required to accommodate Power River Basin coal at selected plants, landfill construction, installation of NO(x) controls, installation of the best technology available for minimizing environmental impacts associated with impingement and entrainment of fish and larvae, particulate matter control improvements, spill prevention controls, and undertaking remedial actions. NRG Energy estimates that it will incur in 2004 at all of its plants in the Northeast Region approximately $23 million in capital expenditures for plant modifications and upgrades required to comply with environmental regulations.

     As of December 31, 2003, we had recorded an accrual of approximately $2.1 million to cover penalties associated with historical opacity exceedances.

     We are responsible for the costs associated with closure, post-closure care and monitoring of the ash landfill owned and operated by us on the site of the Indian River Generating Station. No material liabilities outside such costs are expected. Financial assurance to provide for closure and post-closure-related costs is currently maintained by a trust fund collateralized in the amount of approximately $6.6 million.

     We estimate that we will incur capital expenditures of approximately $14.7 million during the years 2004 through 2008 related to resolving environmental concerns at the Indian River Generating Station. These concerns include the expected closure of the existing ash landfill, the construction of a new ash landfill nearby, the addition of controls to reduce NO(x) emissions, fuel yard modifications, and electrostatic precipitator refurbishments to reduce opacity.

Central Region

     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 us (one of the instruments allowed by the Louisiana Department of Environmental Quality for providing financial assurance for expenses associated with closure and post-closure care of the ponds). The current value of the trust fund is approximately $4.8 million and we are making annual payments to the fund in the amount of about $116,000. See Note 14.

     We estimate approximately $18 million of capital expenditures will be incurred during the period 2004 through 2008 for the addition of NO(x) controls on Units 1 and 2 of Big Cajun II. In addition, NRG Energy estimates that it would incur up to $5 million to reduce particulate matter emissions during start-up of Units 1 and 2 at Big Cajun II.

NYISO Claims

     In November 2002, the NYISO notified us of claims related to New York City mitigation adjustments, general NYISO billing adjustments and other miscellaneous charges related to sales between November 2000 and October 2002. The New York City mitigation adjustments totaled $11.5 million. We did not contest that claim and it has been fully reserved. The general NYISO billing adjustment issue totaled $10.2 million and related to NYISO’s concern that NRG would not have sufficient revenue to cover for subsequent revisions to its energy market settlements. As of December 31, 2003, the NYISO held $4.5 million in escrow for such future settlement revisions.

Conectiv Agreement Termination

     On November 8, 2002 Conectiv provided us with a Notice of Termination of Transaction under the Master Power Purchase and Sale Agreement, or “Master PPA”, dated June 21, 2001. Under the Master PPA, which was assumed by us in our acquisition of various assets from Conectiv, we had been required to deliver 500 MW of electrical energy around the clock at a specified price through 2005. In connection with the Conectiv acquisition, we recorded as an out-of-market contract obligation for this contract. As a result of the cancellation, we will lose approximately $383.1 million in future contracted revenues. Also, in conjunction with the terms of the Master PPA, we received from Conectiv a termination payment in the amount of $955,000. At December 31, 2002, the remaining unamortized balance of the contract obligation was recognized as revenue. As a result, during the fourth quarter approximately $50.7 million was recognized as revenue.

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Legal Issues

California Wholesale Electricity Litigation and Related Investigations

     People of the State of California ex. rel. Bill Lockyer, Attorney General, v. Dynegy, Inc. et al., United States District Court, Northern District of California, Case No. C-02-O1854 VRW; United States Court of Appeals for the Ninth Circuit, Case No. 02-16619.

     This action was filed in state court on March 11, 2002 against us, Dynegy, Dynegy Power Marketing, Inc., Xcel Energy, West Coast Power and four of West Coast Power’s operating subsidiaries. Through our subsidiary, NRG West Coast LLC, we are a 50 percent beneficial owner with Dynegy of West Coast Power, which owns, operates, and markets the power of California plants. Dynegy and its affiliates and subsidiaries are responsible for gas procurement and marketing and trading activities on behalf of West Coast Power. It alleges that the defendants violated California Business & Professions Code § 17200 by selling ancillary services to the Cal ISO, and subsequently selling the same capacity into the spot market. The California Attorney General seeks injunctive relief as well as restitution, disgorgement and civil penalties.

     On April 17, 2002, the defendants removed the case to the United States District Court in San Francisco. Thereafter, the case was transferred to Judge Vaughn Walker, who is also presiding over various other “ancillary services” cases brought by the California Attorney General against other participants in the California market, as well as other lawsuits brought by the Attorney General against these other market participants. We have tolling agreements in place with the Attorney General with respect to such other proposed claims against us.

     The Attorney General filed motions to remand, which the defendants opposed in July of 2002. In an Order filed in early September 2002, Judge Walker denied the remand motions. The Attorney General has appealed that decision to the United States Court of Appeal for the Ninth Circuit, and the appeal is pending. The Attorney General also sought a stay of proceedings in the district court pending the appeal, and this request was also denied. In a lengthy opinion filed March 25, 2003, Judge Walker dismissed the Attorney General’s action against Dynegy and us with prejudice, finding it was barred by the filed-rate doctrine and preempted by federal law. The Attorney General filed a Notice of Appeal, and the appeal was argued in August 2003 and also is pending.

     Public Utility District of Snohomish County v. Dynegy Power Marketing, Inc et al., Case No. 02-CV-1993 RHW, United States District Court, Southern District of California (part of MDL 1405).

     This action was filed against us, Dynegy, Xcel Energy and several other market participants in the United States District Court in Los Angeles on July 15, 2002. The complaint alleges violations of the California Business & Professions Code § 16720 (the Cartwright Act) and Business & Professions Code § 17200. The basic claims are price fixing and restriction of supply, and other market “gaming” activities.

     The action was transferred from Los Angeles to the United States District Court in San Diego and was made a part of the Multi-District Litigation proceeding described below. All defendants filed motions to dismiss and to strike in the fall of 2002. In an Order dated January 6, 2003, Judge Robert Whaley, a federal judge from Spokane sitting in the United States District Court in San Diego, pursuant to the Order of the Multi-District Litigation Panel, granted the motions to dismiss on the grounds of federal preemption and filed- rate doctrine. The plaintiffs have filed a notice of appeal, and the appeal is pending.

     In re: Wholesale Electricity Antitrust Litigation, MDL 1405, United States District Court, Southern District of California, pending before Judge Robert H. Whaley. The cases included in this proceeding are as follows:

     Pamela R Gordon, on Behalf of Herself and All Others Similarly Situated v Reliant Energy, Inc. et al., Case No. 758487, Superior Court of the State of California, County of San Diego (filed on November 27, 2000).

     Ruth Hendricks, On Behalf of Herself and All Others Similarly Situated and On Behalf of the General Public v. Dynegy Power Marketing, Inc. et al.,  Case No. 758565, Superior Court of the State of California, County of San Diego (filed November 29, 2000).

     The People of the State of California, by and through San Francisco City Attorney Louise H. Renne v. Dynegy Power Marketing, Inc. et al.,  Case No. 318189, Superior Court of California, San Francisco County (filed January 18, 2001).

     Pier 23 Restaurant, A California Partnership, On Behalf of Itself and All Others Similarly Situated v PG&E Energy Trading et al.,  Case No. 318343, Superior Court of California, San Francisco County (filed January 24, 2001).

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     Sweetwater Authority, et al. v. Dynegy, Inc. et al., Case No. 760743, Superior Court of California, County of San Diego (filed January 16, 2001).

     Cruz M Bustamante, individually, and Barbara Matthews, individually, and on behalf of the general public and as a representative taxpayer suit, v. Dynegy Inc. et al., inclusive.  Case No. BC249705, Superior Court of California, Los Angeles County (filed May 2, 2001).

     All of West Coast Power’s operating subsidiaries are defendants in at least one of these six consolidated cases, which were all filed in late 2000 and 2001 in various state courts throughout California. They allege unfair competition, market manipulation and price fixing. All the cases were removed to the appropriate United States District Courts, and were thereafter made the subject of a petition to the Multi-District Litigation Panel (Case No. MDL 1405). The cases were ultimately assigned to Judge Whaley. Judge Whaley entered an order in 2001 remanding the cases to state court, and thereafter the cases were coordinated pursuant to state court coordination proceedings before a single judge in San Diego Superior Court. Thereafter, Reliant Energy and Duke Energy filed cross-complaints naming various Canadian, Mexican and United States government entities. Some of these defendants once again removed the cases to federal court, where they were again assigned to Judge Whaley. The defendants filed motions to dismiss and to strike under the filed-rate and federal preemption theories, and the plaintiffs challenged the district court’s jurisdiction and sought to have the cases remanded to state court. In December 2002, Judge Whaley issued an opinion finding that federal jurisdiction was absent in the district court, and remanding the cases to state court. Duke Energy and Reliant Energy then filed a notice of appeal with the Ninth Circuit, and also sought a stay of the remand pending appeal. The stay request was denied by Judge Whaley. On February 20, 2003, however, the Ninth Circuit stayed the remand order and accepted jurisdiction to hear the appeal of Reliant Energy and Duke Energy on the remand order. We anticipate that filed-rate/federal preemption pleading challenges will be renewed once the remand appeal is decided.

     “Northern California” cases against various market participants, not including us (part of MDL 1405). These include the  Millar, Pastorino, RDJ Farms, Century Theatres, EI Super Burrito, Leo’s, J&M Karsant,  and  Bronco Don cases. We were not named in any of these cases, but in virtually all of them, either West Coast Power or one or more of its operating subsidiaries is named as a defendant. These cases all allege violation of Business & Professions Code § 17200, and are similar to the various allegations made by the Attorney General. Dynegy is named as a defendant in all these actions, and Dynegy’s outside counsel is representing both Dynegy and the West Coast Power entities in each of these cases. These cases all were removed to federal court, made part of the Multi-District Litigation, and denied remand to state court. In late August 2003, Judge Whaley granted the defendants’ motions to dismiss in these various cases, which are now the subject of the plaintiff’s appeal to the Ninth Circuit Court of Appeals.

     Bustamante v. McGraw-Hill Companies, Inc., et al., No. BC 235598, California Superior Court, Los Angeles County.

     This putative class action lawsuit was filed on November 20, 2002. The complaint generally alleges that the defendants attempted to manipulate gas indexes by reporting false and fraudulent trades. Named defendants in the suit include numerous industry participants unrelated to us, as well as the operating subsidiaries established by West Coast Power for each of its four plants: El Segundo Power, LLC; Long Beach Generation, LLC; Cabrillo Power I LLC; and Cabrillo Power II LLC. The complaint seeks restitution and disgorgement of “ill-gotten gains,” civil fines, compensatory and punitive damages, attorneys’ fees and declaratory and injunctive relief. The plaintiff filed an amended complaint in 2003.

     Jerry Egger, et al. v. Dynegy, Inc., et al., Case No. 809822, Superior Court of California, San Diego County (filed May 1, 2003). This class action complaint alleges violations of California’s Antitrust Law, Business and Professional Code, and unlawful and unfair business practices. The named defendants include “West Coast Power, Cabrillo II, El Segundo Power, Long Beach Generation.” We are not named. This case now has been removed to the United States District Court, and the defendants have moved to have this case included as Multi-District Litigation along with the above referenced cases before Judge Walker. Plaintiffs have filed a motion to remand to state court, which was heard on February 19, 2004. At the hearing, the court decided to stay the case pending a decision from the Ninth Circuit Court of Appeals in the Pastorino appeal, referenced above.

     Texas-Ohio Energy, Inc., on behalf of Itself and all others similarly situated v. Dynegy, Inc. Holding Co., West Coast Power, LLC, et al.,  Case No. CIV.S-03-2346 DFL GGH. This putative class action was filed on November 10, 2003, in the United States District Court for the Eastern District of California. The complaint alleges violations of the federal Sherman and Clayton Acts and California’s Cartwright Act and Business and Professions Code. In addition to naming West Coast Power and Dynegy the complaint names numerous industry participants, as well as “unnamed co-conspirators.” The complaint alleges that defendants conspired to manipulate the spot price and basis differential of natural gas with respect to the California market allegedly enabling defendants to reap exorbitant and illicit profits by gouging natural gas purchasers. Specifically, the complaint alleges that defendants and their co-

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conspirators employed a variety of false reporting techniques to manipulate the published natural gas price indices. The complaint seeks unspecified amounts of damages, including a trebling of plaintiff’s and the putative class’s actual damages. We are unable at this time to predict the outcome of this dispute or the ultimate liability, if any, of West Coast Power.

California Investigations

FERC — California Market Manipulation

     The Federal Energy Regulatory Commission has an ongoing “Investigation of Potential Manipulation of Electric and Natural Gas Prices,” which involves hundreds of parties (including our affiliate, West Coast Power) and substantial discovery. In June 2001, FERC initiated proceedings related to California’s demand for $8.9 billion in refunds from power sellers who allegedly inflated wholesale prices during the energy crisis. Hearings have been conducted before an administrative law judge who issued an opinion in late 2002. The administrative law judge stated that after assessing a refund of $1.8 billion for “unjust and unreasonable” power prices between October 2, 2000 and June 20, 2001, power suppliers were owed $1.2 billion because the State was holding funds owed to suppliers.

     In August 2002, the United States Circuit Court of Appeals for the Ninth Circuit granted a request by the Electricity Oversight Board, the California Public Utilities Commission and others, to seek out and introduce to FERC additional evidence of market manipulation by wholesale sellers. This decision resulted in FERC ordering an additional 100 days of discovery in the refund proceeding, and also allowing the relevant time period for potential refund liability to extend back an additional nine months, to January 1, 2000.

     On December 12, 2002, FERC Administrative Law Judge Birchman issued a Certification of Proposed Findings on California Refund Liability in Docket No. EL00-95-045 et al., which determined the method for calculating the mitigated energy market clearing price during each hour of the refund period. On March 26, 2003, FERC issued an Order on Proposed Findings on Refund Liability in Docket No. EL00-95-045, or “Refund Order”, adopting, in part, and modifying, in part, the Proposed Findings issued by Judge Birchman on December 12, 2002. In the Refund Order, FERC adopted the refund methodology in the Staff Final Report on Price Manipulation in Western Markets issued contemporaneously with the Refund Order in Docket No. PA02-2-000. This refund calculation methodology makes certain changes to Judge Birchman’s methodology, because of FERC Staff’s findings of manipulation in gas index prices. This could materially increase the estimated refund liability. The Refund Order directed generators wanting to recover any fuel costs above the mitigated market clearing price during the refund period to submit cost information justifying such recovery within 40 days of the issuance of the Refund Order, which West Coast Power did. Dynegy and the West Coast Power entities are currently engaged in settlement negotiations with FERC Staff, the California Attorney General, the California Public Utility Commission, the California Electricity Oversight Board, PG&E, and Southern California Edison.

CFTC — Dynegy/West Coast Power Natural Gas Futures Index Manipulation

     On December 18, 2002, a Dynegy subsidiary, Dynegy Marketing & Trade, or “DMT”, and West Coast Power, collectively “the Respondents”, entered into a consent Offer of Settlement and Order, “the Consent Order”, with the Commodity Futures and Trading Commission, or “CFTC.” The action is captioned In re Dynegy Marketing & Trade and West Coast Power LLC, CFTC Docket No. 03-03. The CFTC asserted various violations of the Commodity Exchange Act, as well as CFTC regulations.

     The CFTC alleged in the Consent Order that DMT natural gas traders reported false natural gas trading information, including price and volume information, to certain industry publications that establish and publish indexes for natural gas prices. The CFTC alleged that DMT submitted the false information in an attempt to manipulate the indexes for DMT’s benefit. The CFTC further alleged that DMT traders directed other Dynegy personnel to report each of the same false trades in the name of West Coast Power, as counterparty, in an effort to lend credence to the trades’ validity. The Respondents to the Consent Order did not admit or deny the allegations or findings made by the CFTC, but agreed to an Offer of Settlement, and agreed to pay a civil monetary fine of $5 million. The Respondents also agreed to undertakings regarding further cooperation with the CFTC and public statements concerning the Consent Order. Dynegy agreed to pay and be entirely responsible for the $5 million fine imposed by the CFTC.

U.S. Attorney — Houston

     The U.S. Attorney indicted two fired Dynegy traders in connection with the index reporting scheme, and is reportedly investigating other Dynegy activity and employees.

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U.S. Attorney — San Francisco

     According to press reports, the U.S. Attorney in San Francisco has assembled an “energy crisis” task force. While Dynegy received a grand jury subpoena in November 2002, the scope and targets of this investigation are unknown to us. We did not receive a subpoena.

California State Senate Select Committee

     This Committee, chaired by Senator Dunn, subpoenaed records from us during the Summer of 2001. We produced about 5,000 pages of documents; Dynegy produced a much larger volume of documents. The Committee has apparently concluded its activities without issuing any reports or findings.

CPUC

     The CPUC continues to request data and documents in several settings. First, it is one of the parties in the FERC proceeding mentioned above. Second, inspectors have visited West Coast Power plants, usually unannounced and usually immediately following an unplanned outage. They have demanded documentation concerning the reason for the outage. Third, the CPUC has demanded documents to allow it to prepare “reports,” one of which was issued in the fall of 2002, and another of which was issued January 30, 2003. The FERC’s above-referenced March 26 Refund Order undercut the accuracy and reliability of these CPUC reports. Dynegy has made extensive productions to the CPUC of plant-related materials as well as trading data.

California Attorney General

     In addition to the litigation it has undertaken described above, the California Attorney General has undertaken an investigation entitled “In the Matter of the Investigation of Possibly Unlawful, Unfair, or Anti-Competitive Behavior Affecting Electricity Prices in California.” In this connection, the Attorney General has issued subpoenas to Dynegy, served interrogatories on Dynegy and us, and informally requested documents and interviews from Dynegy and Dynegy employees as well as us and our employees. We responded to the interrogatories in the summer of 2002, with the final set of responses being served on September 3, 2002. We have also produced a large volume of documentation relating to the West Coast Power plants. In addition, our employees in California have sat for informal interviews with representatives of the Attorney General’s office. Dynegy employees have also been interviewed.

     On November 21, 2003, in conjunction with confirmation of the NRG plan of reorganization, we reached an agreement with the Attorney General and the State of California, generally, whereby for purposes of distributions, if any, to be made to the State of California under the NRG plan of reorganization, the liquidated amount of any and all allowed claims shall not exceed $1.35 billion in the aggregate. The agreement neither affects our right to object to these claims on any and all grounds nor admits any liability whatsoever. We further agreed to waive any objection to the liquidation of these claims in a non-bankruptcy forum having proper jurisdiction.

     Although any evaluation of the likelihood of an unfavorable outcome or an estimate of the amount or range of potential loss in the above-referenced private actions and various investigations cannot be made at this time, we note that the Gordon complaint alleges that the defendants, collectively, overcharged California ratepayers during 2000 by $4.0 billion. We know of no evidence implicating us in the various private plaintiffs’ allegations of collusion. We cannot predict the outcome of these cases and investigations at this time.

Electricity Consumers Resource Council v. Federal Energy Regulatory Commission, Case No. 03-1449

     On December 19, 2003 the Electricity Consumers Resource Council, or “ECRC”, appealed to the United States Court of Appeals for the District of Columbia Circuit a recent decision by FERC approving the implementation of a demand curve for the New York installed capacity, or “ICAP”, market. ECRC claims that the implementation of the ICAP demand curve violates section 205 of the Federal Power Act because it constitutes unreasonable ratemaking. We are a party to this appeal and will contest ECRC’s assertions, but at this time cannot assess what the eventual outcome will be.

Connecticut Light & Power Company v. NRG Power Marketing, Inc., Docket No. 3:01-CV-2373 (AWT), pending in the United States District Court, District of Connecticut

     This matter involves a claim by CL&P for recovery of amounts it claims are owing for congestion charges under the terms of a SOS contract between the parties, dated October 29, 1999. CL&P has served and filed its motion for summary judgment to which PMI

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filed a response on March 21, 2003. CL&P has withheld approximately $30 million from amounts owed to PMI, claiming that it has the right to offset those amounts under the contract. PMI has counterclaimed seeking to recover those amounts, arguing among other things that CL&P has no rights under the contract to offset them. By reason of the previous bankruptcy stay, the court has not ruled on the pending motion. On November 6, 2003, the parties filed a joint stipulation for relief from the automatic stay in order to allow the proceeding to go forward. PMI cannot estimate at this time the likelihood of an unfavorable outcome in this matter, or the overall exposure for congestion charges for the full term of the contract.

Connecticut Light & Power Company, Docket No. EL03-135, pending at the Federal Energy Regulatory Commission

     This matter involves a dispute between CL&P and PMI concerning which of party is responsible, under the terms of the October 29, 1999 SOS contract, for costs related to congestion and losses associated with the implementation of standard market design, or “SMD-Related Costs.” CL&P has withheld, in addition to the $30 million discussed above, approximately $79 million from amounts owed to PMI, claiming that it is entitled under the contract to offset those additional amounts for SMD-Related Costs. The parties have now reached a settlement, subject to board approval, whereby CL&P will pay PMI $38.4 million plus interest, and subject to adjustments and true-ups upon final approval by FERC. The settlement agreement was filed with FERC on March 3, 2004.

The State of New York and Erin M. Crotty, as Commissioner of the New York State Department of Environmental Conservation v. Niagara Mohawk Power Corporation et al., United States District Court for the Western District of New York, Civil Action No. 02-CV-002S

     In January 2002, the New York Department of Environmental Conservation, or “DEC”, sued Niagara Mohawk Power Corporation, or “NiMo”, and us in federal court in New York. The complaint asserted that projects undertaken at our Huntley and Dunkirk plants by NiMo, the former owner of the facilities, required preconstruction permits pursuant to the Clean Air Act and that the failure to obtain these permits violated federal and state laws. In July, 2002, we filed a motion to dismiss. On March 27, 2003, the court dismissed the complaint against us with prejudice as to the federal claims and without prejudice as to the state claims. It is possible the state will appeal this dismissal to the Second Circuit Court of Appeals. In the meantime, on December 31, 2003, the trial court granted the state’s motion to amend the complaint to again sue us and various affiliates in this same action in the federal court in New York, asserting against us violations of operating permits and deficient operating permits at the Huntley and Dunkirk plants. If the case ultimately is litigated to an unfavorable outcome that could not be addressed otherwise, we have estimated that the total investment that would be required to install pollution control devices could be as high as $300 million over a ten to twelve-year period. We also could be found responsible for payment of certain penalties and fines.

Niagara Mohawk Power Corporation v. NRG Energy, Inc., Huntley Power, LLC, and Dunkirk Power, LLC, Supreme Court, State of New York, County of Onondaga, Case No. 2001-4372

     We have asserted that NiMo is obligated to indemnify it for any related compliance costs associated with resolution of the above enforcement action. NiMo has filed suit in state court in New York seeking a declaratory judgment with respect to its obligations to indemnify us under the asset sales agreement. We have pending a summary judgment motion on its entitlement to be reimbursed by NiMo for the attorneys’ fees we have incurred in the enforcement action.

Huntley Power LLC, Dunkirk Power LLC and Oswego Power LLC

     The DEC has alleged violations by the Huntley Generating Station, the Dunkirk Generating Station and the Oswego Generating Station with respect to opacity exceedances. The above entities have been engaged in consent order negotiations with the DEC relative to such opacity issues affecting all three facilities since the plants were acquired. In late February, 2004, a representative of each of the six entities signed a proposed final version of the consent order, which, if executed and thereby issued by the DEC, would quantify the number of opacity exceedances at the three facilities through the second quarter of 2003 and assess a cumulative penalty of $1 million. In addition, among other provisions, the consent order would establish stipulated penalties for future violations of opacity requirements and of the consent order and impose a Schedule of Compliance. In the event that the consent order is not issued by DEC in the form in which it was agreed to by the six entities and any subsequent negotiations prove unsuccessful, it is not known what relief the DEC will seek through an enforcement action and what the result of such action will be.

Huntley Power LLC

     On April 30, 2003, the Huntley Station submitted a self-disclosure letter to the DEC reporting violations of applicable sulfur in fuel limits, which had occurred during 6 days in March 2003 at the chimney stack serving Huntley Units 63-66. The Huntley Station

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self-disclosed that the average sulfur emissions rates for those days had been 1.8 lbs/mm BTU, rather than the maximum allowance of 1.7 lbs/mm BTU. NRG Huntley Operations discontinued use of Unit 65 (the only unit utilizing the subject stack at the time) and has kept the remaining three units off line until adherence with the applicable standard is assured. On May 19, 2003, the DEC issued Huntley Power LLC a Notice of Violation. Huntley Power LLC has met with the DEC to discuss the circumstances surrounding the event and the appropriate means of resolving the matter. Huntley Power LLC does not know what relief the DEC will seek through an enforcement action. Under applicable provisions of the Environmental Conservation Law, the DEC asserts that it may impose a civil penalty up to $10,000, plus an additional penalty not to exceed $10,000 for each day that a violation continues and may enjoin continuing violations.

Niagara Mohawk Power Corporation v. Dunkirk Power LLC, NRG Dunkirk Operations, Inc., Huntley Power LLC, NRG Huntley Operations, Inc., Oswego Power LLC and NRG Oswego Operations, Inc., Supreme Court, Erie County, Index No. 1-2000-8681 — Station Service Dispute

     On October 2, 2000, plaintiff NiMo commenced this action against us to recover damages plus late fees, less payments received through the date of judgment, as well as any additional amounts due and owing, for electric service provided to the Dunkirk Plant after September 18, 2000. Plaintiff NiMo claims that we have failed to pay retail tariff amounts for utility services commencing on or about June 11, 1999 and continuing to September 18, 2000 and thereafter. Plaintiff has alleged breach of contract, suit on account, violation of statutory duty and unjust enrichment claims. On or about October 23, 2000, we served an answer denying liability and asserting affirmative defenses.

     After proceeding through discovery, and prior to trial, the parties and the court entered into a Stipulation and Order filed August 9, 2002 consolidating this action with two other actions against our Huntley and Oswego subsidiaries, both of which cases assert the same claims and legal theories for failure to pay retail tariffs for utility services at those plants.

     On October 8, 2002, a Stipulation and Order was filed in the Erie County Clerk’s Office staying this action pending submission to FERC of some or all of the disputes in the action. We cannot make an evaluation of the likelihood of an unfavorable outcome. The cumulative potential loss could exceed $35 million.

Niagara Mohawk Power Corporation v. Huntley Power LLC, NRG Huntley Operations, Inc., NRG Dunkirk Operations, Inc., Dunkirk Power LLC, Oswego Harbor Power LLC, and NRG Oswego Operations, Inc., Case Filed November 26, 2002 in Federal Energy Regulatory Commission Docket No. EL 03-27-000

     This is the companion action filed by NiMo at FERC, similarly asserting that NiMo is entitled to receive retail tariff amounts for electric service provided to the Huntley, Dunkirk and Oswego plants. On October 31, 2003, the FERC Trial Staff, a party to the proceedings, filed a reply brief in which it supported and agreed with each position taken by our facilities. In short, the staff argued that our facilities: (1) self-supply station power under the NYISO tariff (which took effect on April 1, 2003) in any month during which they produce more energy than they consume and, as such, should not be assessed a retail rate; (2) are connected only to transmission facilities and, as such, at most should only pay NiMo a FERC-approved transmission rate; and (3) should be allowed to net consumption and output even if power is injected into the grid at a different point from which it is drawn off. We are presently awaiting a ruling by FERC. At this stage of the proceedings, we cannot estimate the likelihood of success on this action. As noted above, the cumulative potential loss could exceed $35 million.

In the Matter of Louisiana Generating, LLC, Adversary Proceeding No. 2002-1095 1-EQ on the docket of the Louisiana Division of Administrative Law

     During 2000, DEQ issued a Part 70 Air Permit modification to Louisiana Generating to construct and operate two 120 MW natural gas-fired turbines. The Part 70 Air Permit set emissions limits for the criteria air pollutants, including NO(x), based on the application of Best Available Control Technology, or “BACT.” The BACT limitation for NO(x) was based on the guarantees of the manufacturer, Siemens-Westinghouse. Louisiana Generating sought an interim emissions limit to allow Siemens-Westinghouse time to install additional control equipment. To establish the interim limit, DEQ issued a Compliance Order and Notice of Potential Penalty, No. AE-CN-02-0022, on September 8, 2002, which is, in part, subject to the referenced administrative hearing. DEQ alleged that Louisiana Generating did not meet its NO(x) emissions limit on certain days, did not conduct all opacity monitoring and did not complete all record keeping and certification requirements. Louisiana Generating intends to vigorously defend certain claims and any future penalty assessment, while also seeking an amendment of its limit for NO(x). An initial status conference was held with the Administrative Law Judge and quarterly reports are being submitted to that judge to describe progress, including settlement and amendment of the limit. In late February 2004, we timely submitted to the DEQ an amended BACT analysis and amended Prevention

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of Significant Deterioration and Title V permit application to amend the NO(x) limit. In addition, Louisiana Generating may assert breach of warranty claims against the manufacturer. With respect to the administrative action described above, at this time we are unable to predict the eventual outcome of this matter or the potential loss contingencies, if any, to which we may be subject.

NRG Sterlington Power, LLC

     During 2002, NRG Sterlington conducted a review of the Sterlington Power Facility’s Part 70 Air Permit obtained by the facility’s former owner and operator, Koch Power, Inc. Koch had outlined a plan to install eight 25 MW capacity turbines to reach a 200 MW capacity limit in the permit. Due to the inability of several units to reach their nameplate capacity, Koch determined that it would need additional units to reach the electric output target. In August 2000, NRG Sterlington acquired the remaining interests in the facility not originally held on a passive basis and sought the transfer of the Part 70 Air Permit along with a modification to incorporate two 17.5 MW turbines installed by Koch and to increase the total number of turbines to ten. The permit modification was issued February 13, 2002. During further review, NRG Sterlington determined that a ninth unit had been installed prior to issuance of the permit modification. In keeping with its environmental policy, it disclosed this matter to DEQ in April, 2002. NRG Sterlington provided to DEQ additional information during July 2002. A Consolidated Compliance Order & Notice of Potential Penalty, No. AE-CN-01-0393, was issued by DEQ on September 10, 2003, wherein DEQ formally alleged that NRG Sterlington did not complete all certification requirements, and installed a ninth unit prior to issuance of its permit modification. We met with DEQ on November 19, 2003 to discuss mitigating circumstances and a settlement has been agreed to between the parties. Under the settlement agreement, without admitting any liability, NRG Sterlington has agreed to pay DEQ the sum of $4,500. The agreement is subject to a public comment period and review by the Louisiana attorney general.

United States Environmental Protection Agency Request for Information under Section 114 of the Clean Air Act

     On January 27, 2004, Louisiana Generating, LLC and Big Cajun II received a request for information under Section 114 of the Clean Air Act from the United States Environmental Protection Agency, or “EPA”, seeking information primarily relating to physical changes made at Big Cajun II in 1994 and 1995 by the predecessor owner of that facility. Louisiana Generating, LLC and Big Cajun II intend to respond to the EPA request in an appropriate and cooperative manner. At the present time, we cannot predict the probable outcome in this matter.

General Electric Company and Siemens Westinghouse Turbine Purchase Disputes

     We and/or our affiliates have entered into several turbine purchase agreements with affiliates of General Electric Company, or “GE” and Siemens Westinghouse Power Corporation, or “Siemens.” GE and Siemens have notified us that we are in default under certain of those contracts, terminated such contracts, and demanded that we pay the termination fees set forth in such contracts. GE’s claim amounts to $120 million and Siemens’ approximately $45 million in cumulative termination charges. We cannot estimate the likelihood of unfavorable outcomes in these disputes.

Itiquira Energetica, S.A.

     Our indirectly controlled Brazilian project company, Itiquira Energetica S.A., the owner of a 156 MW hydro project in Brazil, is currently in arbitration with the former EPC contractor for the project, Inepar Industria e Construcoes, or “Inepar.” The dispute was commenced by Itiquira in September of 2002 and pertains to certain matters arising under the former EPC contract. Itiquira principally asserts that Inepar breached the contract and caused damages to Itiquira by (i) failing to meet milestones for substantial completion; (ii) failing to provide adequate resources to meet such milestones; (iii) failing to pay subcontractors amounts due; and (iv) being insolvent. Itiquira’s arbitration claim is for approximately U.S. $40 million. Inepar has asserted in the arbitration that Itiquira breached the contact and caused damages to Inepar by failing to recognize events of force majeure as grounds for excused delay and extensions of scope of services and material under the contract. Inepar’s damage claim is for approximately U.S. $10 million. The parties submitted their respective statements of claims, counterclaims and responses, and a preliminary arbitration hearing was held on March 21, 2003. In lieu of taking expert testimony at hearing, the court of arbitration ordered an expert investigation process to cover technical and accounting issues. We anticipate that the final report from the expert investigation process will be delivered to the court of arbitration in the last week of March, 2004. After reviewing the final report, the court of arbitration may, if it deems it necessary, require expert testimony on technical and accounting issues, which we anticipate would commence on approximately May 15, 2004. We expect the arbitration panel to issue its decision no later than July 31, 2004. We cannot estimate the likelihood of an unfavorable outcome in this dispute.

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CFTC Trading Inquiry

     On June 17, 2002, the CFTC served Xcel Energy, on behalf of its affiliates, which then included us and PMI, with a subpoena requesting certain information regarding “round trip” or “wash” trading and general trading practices in its investigation of several energy trading companies. The CFTC now appears focused on possible efforts by traders to submit false reports to index publications in an attempt to manipulate the index. In January, 2004, the CFTC and Xcel Energy’s subsidiary e prime, inc., reached a settlement in connection with this investigation, which included the payment of a $16 million fine and the entry of a cease and desist order. Other industry participants that have settled with the CFTC have paid fines of between $1 million and $30 million and have agreed to the terms of cease and desist orders. The CFTC has requested additional related information from us and has subpoenaed to appear for testimony a number of our present and former employees. We have sought to cooperate with the CFTC and have submitted materials responsive to the CFTC’s requests, while vigorously denying that we engaged in any improper conduct. We cannot at this time predict the outcome or financial impact of this investigation.

Additional Litigation

     In addition to the foregoing, we are parties to other litigation or legal proceedings, which may or may not be material. There can be no assurance that the outcome of such matters will not have a material adverse effect on our business, financial condition or results of operations.

Disputed Claims Reserve

     As part of the NRG plan of reorganization, we have 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, to the extent such claims are resolved now that we have emerged from bankruptcy, the claimants will be paid from the reserve on the same basis as if they had been paid out in the bankruptcy. That means that their allowed claims will be reduced to the same recovery percentage as other creditors would have received and will be paid in pro rata distributions of cash and common stock. We believe we have funded the disputed claims reserve is at a sufficient level to settle the remaining unresolved proofs of claim we received during the bankruptcy proceedings. However, to the extent the aggregate amount of these payouts of disputed claims ultimately exceeds the amount of the funded claim reserve, we are obligated to provide additional cash and common stock to the disputed claims reserve. We will continue to monitor our obligation as the disputed claims are settled. However, if excess funds remain in the disputed claims reserve after payment of all obligations, such amounts will be reallocated to the Creditor Pool. We have provided our common stock and cash contribution to an escrow agent to complete the distribution and settlement process. Since we have surrendered control over the common stock and cash provided to the disputed claims reserve, we recognized the issuance of the common stock as of December 6, 2003 and removed the cash amounts from our balance sheet. Similarly, we have moved the obligations relevant to the claims from our balance sheet when the common stock was issued and cash contributed.

     In conjunction with confirmation of the NRG plan of reorganization, we reached an agreement with the Attorney General and the State of California that limits the potential maximum amount of its claims, if any. Under the NRG plan of reorganization, the liquidated amount of any allowed claims shall not exceed $1.35 billion in total. The agreement neither affects our right to object to these claims on any grounds nor admits any liability. We further agreed to waive any objection to the liquidation of these claims in a non-bankruptcy forum having proper jurisdiction. Although we cannot make at this time any evaluation of the likelihood of an unfavorable outcome or an estimate of the amount or range of potential loss in the private actions and various investigations, we know of no evidence implicating us in the various private plaintiffs’ allegations of collusion. We cannot predict the outcome of these cases and investigations at this time.

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Note 25 — Cash Flow Information

     Detail of supplemental disclosures of cash flow and non-cash investing and financing information was:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	Reorganized	
 	 	Predecessor Company

	 	NRG

	
 	 	 	 	 	 	 	 	 	 	For the Period	 	For the Period	
 	 	Year Ended December 31,

	 	January 1 -
December 5,	 	December 6 -
December 31,	
 	 	2001

	 	2002

	 	2003

	 	2003

	
 	 	 	 	 	 	(In thousands)	 	 	 	 	
Interest paid (net of amount capitalized)	 	$	385,885	 	 	$	331,679	 	 	$	182,355	 	 	$	86,874	 	
Income taxes paid/(refunds)	 	$	57,055	 	 	$	(17,406	)	 	$	27,064	 	 	$	1,726	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Detail of businesses and assets acquired:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current assets (including restricted cash)	 	$	184,874	 	 	$	—	 	 	$	—	 	 	$	—	 	
Fair value of non-current assets	 	 	4,779,530	 	 	 	—	 	 	 	—	 	 	 	—	 	
Liabilities assumed, including deferred taxes	 	 	(2,151,287	)	 	 	—	 	 	 	—	 	 	 	—	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Cash paid net of cash acquired	 	$	2,813,117	 	 	$	—	 	 	$	—	 	 	$	—	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Reorganization Cash Payments and Receipts

Cash Receipts

     During the period May 14, 2003 through December 31, 2003, we received $1.1 million of interest income on cash balances. No such amounts were received during the period December 6, 2003 through December 31, 2003.

Cash Payments

Professional fees

     During the period May 14, 2003 through December 5, 2003 and December 6, 2003 through December 31, 2003, we made cash payments for professional fees to our financial and legal advisors of $33.5 million and $14.4 million, respectively.

Refinancing activities

     We made cash payments of $1.3 billion related to the repayment of NRG Northeast Generating and NRG South Central Generating’s debt, including accrued interest upon their emergence from bankruptcy on December 23, 2003 with proceeds from our recently completed corporate level refinancing. We also made cash payments of $19.6 million for a prepayment settlement upon our early payment of the NRG Northeast Generating and NRG South Central Generating debt.

Creditor payments

     Upon our emergence from bankruptcy, we made cash payments to our creditors in the amounts of $518.6 million during the period December 6, 2003 through December 31, 2003.

Note 26 — Guarantees

     In November 2002, the FASB issued FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.”  The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor’s fiscal year-end. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002. The interpretation addresses the disclosures to be made by a guarantor in its interim and annual financial

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statements about its obligations under guarantees. The interpretation also clarifies the requirements related to the recognition of a liability by a guarantor at the inception of the guarantee for the obligations the guarantor has undertaken in issuing the guarantee.

     In connection with the adoption of Fresh Start, all outstanding guarantees were considered new; accordingly we applied the provisions of FIN 45 to all of those guarantees. Each guarantee was reviewed for the requirement to recognize a liability at inception. As a result, we recorded a $15.0 million liability, which is included in other long-term liabilities.

     We are directly liable for the obligations of certain of our project affiliates and other subsidiaries pursuant to guarantees relating to certain of their indebtedness, equity and operating obligations. In addition, in connection with the purchase and sale of fuel, emission credits and power generation products to and from third parties with respect to the operation of some of our generation facilities in the United States, we may be required to guarantee a portion of the obligations of certain of our subsidiaries. Additionally, as a result of the downgrades of our unsecured debt ratings, we were required to but failed to post cash collateral in the amount of $71.4 million as of December 31, 2003. At the time of the January 6, 2004 restructuring of the project financing of NRG Peaker Finance Co., LLC, this equity contribution requirement was extinguished and was replaced with a $36.2 million NRG Energy letter of credit, for the benefit of the secured parties in the Peaker financing, as well as other provisions of the restructuring.

     As of December 31, 2002, December 6, 2003 and December 31, 2003, our obligations pursuant to our guarantees of the performance, equity and indebtedness obligations of our subsidiaries were as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor	 	 	
 	 	Company

	 	Reorganized NRG

	
 	 	December 31	 	December 6	 	December 31	
Description

	 	2002

	 	2003

	 	2003

	
 	 	 	 	 	 	(In thousands)	 	 	 	 	
Guarantees of subsidiaries	 	$	1,587,022	 	 	$	601,859	 	 	$	564,114	 	
Standby letters of credit	 	 	110,676	 	 	 	90,360	 	 	 	92,050	 	

 	 	 	 	

 	 	 	 	

 	 	
Total guarantees	 	$	1,697,698	 	 	$	692,219	 	 	$	656,164	 	

 	 	 	 	

 	 	 	 	

 	 	
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As of December 6, 2003 and December 31, 2003, the nature and details of our guarantees were as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Maximum	 	Maximum	 	 	 	 	 	 	
 	 	Amount	 	Amount	 	 	 	 	 	 	
Project or	 	(Dec. 6, 2003)	 	(Dec. 31, 2003)	 	 	 	 	 	 	
Subsidiary

	 	(In thousands)

	 	(In thousands)

	 	Nature of Guarantee

	 	Expiration Date

	 	Triggering Event

	
Astoria/Arthur	 	Indeterminate	 	Indeterminate	 	Performance under	 	None stated	 	Non-performance	
Kill	 	 	 	 	 	 	 	 	 	Purchase and Sale	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Agreement	 	 	 	 	 	 	 	 	
Cadillac	 	$	773	 	 	$	778	 	 	Obligation under	 	April 15, 2007	 	Non-payment	
 	 	 	 	 	 	 	 	 	 	Promissory Note	 	 	 	 	 	 	 	 	
Elk River	 	$	14,090	 	 	$	11,990	 	 	Obligation under	 	Undetermined	 	Non-payment of	
 	 	 	 	 	 	 	 	 	 	Bond Arrangement	 	 	 	 	 	Obligation	
 	 	 	 	 	 	 	 	 	 	with NSP	 	 	 	 	 	 	 	 	
Flinders	 	$	9,244	 	 	$	9,125	 	 	Superannuation	 	September 8,	 	Credit Agreement	
 	 	 	 	 	 	 	 	 	 	(pension) Reserve	 	2012	 	 	 	Default	
Flinders	 	$	51,555	 	 	$	52,703	 	 	Debt Service Reserve	 	September 8,	 	Credit Agreement	
 	 	 	 	 	 	 	 	 	 	Guarantee	 	2012	 	 	 	Default	
Flinders	 	$	59,964	 	 	$	61,601	 	 	Plant Removal and	 	Undetermined,	 	Non-performance	
 	 	 	 	 	 	 	 	 	 	Site Remediation	 	at end of site	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Obligation	 	lease	 	 	 	 	
Flinders	 	$	73,650	 	 	$	75,290	 	 	Guarantee of	 	None stated	 	Non-payment	
 	 	 	 	 	 	 	 	 	 	Employee Separation	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Benefits	 	 	 	 	 	 	 	 	
Flinders (Flinders	 	$	249,281	 	 	$	252,487	 	 	Guarantee of	 	None stated	 	Non-payment	
Osborne Trading)	 	 	 	 	 	 	 	 	 	Obligation to	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Purchase Gas	 	 	 	 	 	 	 	 	
Flinders (Flinders	 	Indeterminate	 	Indeterminate	 	Indemnification of	 	Fourth quarter	 	Non-payment	
Osborne Trading)	 	 	 	 	 	 	 	 	 	Government Entity	 	2018	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	for Payment for	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Power and Fuel	 	 	 	 	 	 	 	 	
Gladstone	 	$	23,699	 	 	$	24,346	 	 	Payment of Penalties	 	None stated	 	Non-performance	
 	 	 	 	 	 	 	 	 	 	in the Event of an	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Extraordinary	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Operational Breach	 	 	 	 	 	 	 	 	
Gladstone	 	Indeterminate	 	Indeterminate	 	Obligations under	 	March 31, 2009	 	Non-performance	
 	 	 	 	 	 	 	 	 	 	Credit Agreement	 	 	 	 	 	 	 	 	
McClain	 	$	1,015	 	 	$	1,015	 	 	Obligation to Fund	 	None stated	 	Non-payment of	
 	 	 	 	 	 	 	 	 	 	Debt Service Reserve	 	 	 	 	 	Subsidiary	
 	 	 	 	 	 	 	 	 	 	Shortfall	 	 	 	 	 	Obligation	
MIBRAG	 	$	8,296	 	 	$	8,601	 	 	Guarantee of Share	 	None stated	 	Non-performance	
 	 	 	 	 	 	 	 	 	 	Purchase Agreement	 	 	 	 	 	 	 	 	
Newport	 	$	9,700	 	 	$	7,500	 	 	Obligation under	 	Undetermined	 	Non-payment of	
 	 	 	 	 	 	 	 	 	 	Bond Arrangement	 	 	 	 	 	Obligation	
 	 	 	 	 	 	 	 	 	 	with NSP	 	 	 	 	 	 	 	 	
PMI	 	$	99,093	 	 	$	57,179	 	 	Guarantees of NRG	 	Various	 	Non-performance	
 	 	 	 	 	 	 	 	 	 	Energy, Inc. on	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	behalf of NRG Power	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Marketing Inc. for	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	various projects	 	 	 	 	 	 	 	 	
Saguaro	 	$	754	 	 	$	754	 	 	Guarantee of Tax	 	Undetermined	 	Non-payment	
 	 	 	 	 	 	 	 	 	 	Indemnity Payments	 	 	 	 	 	 	 	 	
SLAP I	 	Indeterminate	 	Indeterminate	 	Guarantee of	 	None stated	 	Non-performance	
 	 	 	 	 	 	 	 	 	 	Subscription	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Agreement in Favor	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	of Scudder Latin	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	American Power I-P	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	LDC and I-C LDC	 	 	 	 	 	 	 	 	
West Coast LLC	 	$	744	 	 	$	744	 	 	Guarantee of	 	None stated	 	Non-performance	
 	 	 	 	 	 	 	 	 	 	Environmental Clean-	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	up Costs	 	 	 	 	 	 	 	 	
West Coast LLC	 	Indeterminate	 	Indeterminate	 	Continuing	 	None stated	 	Non-performance	
 	 	 	 	 	 	 	 	 	 	Obligations Under	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Asset Sales	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Agreement and	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Related Contracts	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	(shared with Dynegy)	 	 	 	 	 	 	 	 	
     Recourse provisions for each of the guarantees above are to the extent of their respective liability. Additionally, no assets are held as collateral for any of the above guarantees.

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     As of December 6, 2003 and December 31, 2003, the nature and details of our unmet cash collateral obligations were as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Maximum	 	Maximum	 	 	 	 	 	 	
 	 	Amount	 	Amount	 	 	 	 	 	 	
 	 	(Dec. 6, 2003)	 	(Dec. 31, 2003)	 	Nature of Collateral	 	 	 	 	
Project

	 	(In thousands)

	 	(In thousands)

	 	Call

	 	Expiration Date

	 	Triggering Event

	
NRG Peaker Finance	 	$	71,472	 	 	$	71,472	 	 	Penalty for Early	 	June 18, 2019	 	Non-performance	
Company LLC	 	 	 	 	 	 	 	 	 	Termination	 	 	 	 	 	 	 	 	
Note 27 — Sales to Significant Customers

Reorganized NRG

     For the period from December 6, 2003 through December 31, 2003, we derived approximately 39.1% of our total revenues from majority-owned operations from two customers: NYISO (26.5%) and ISO New England (12.6%).

Predecessor Company

     For the period from January 1, 2003 through December 5, 2003, sales to one customer (NYISO) accounted for 33.4% of our total revenues from majority owned operations. During 2002, sales to one customer (NYISO) accounted for 26.0% of our total revenues from majority owned operations in 2002. During 2001, sales to two customers accounted for 35.6% (NYISO) and 18.5% (Connecticut Light and Power Co.) of our total revenues from majority owned operations in 2001.

Note 28 — Jointly Owned Plants

Big Cajun II Unit 3

     On March 31, 2000, we acquired a 58% interest in the Big Cajun II, Unit 3 generation plant. Entergy Gulf States owns the remaining 42%. Big Cajun II, Unit 3 is operated and maintained by Louisiana Generating pursuant to a joint ownership participation and operating agreement. Under this agreement, Louisiana Generating and Entergy Gulf States are each entitled to their ownership percentage of the hourly net electrical output of Big Cajun II, Unit 3. All fixed costs are shared in proportion to the ownership interests. Fixed costs include the cost of operating common facilities. All variable costs are incurred in proportion to the energy delivered to the owners. Our income statement includes its share of all fixed and variable costs of operating the unit.

Reorganized NRG

     Our 58% share of the Property, Plant and Equipment and construction in progress as revalued to fair value upon the adoption of the fresh start provisions of SOP 90-7 at December 6, 2003 and December 31, 2003 was $183.2 million and $183.2 million and corresponding accumulated depreciation and amortization was $0 million and $0.5 million, respectively.

Predecessor Company

     Our 58% share of the original cost included in Property, Plant and Equipment and construction in progress at December 31, 2002 was $189.0 million and corresponding accumulated depreciation and amortization was $12.3 million.

Keystone and Conemaugh

     In June 2001, we completed the acquisition of an approximately 3.7% interest in both the Keystone and Conemaugh coal-fired generating facilities. The Keystone and Conemaugh facilities are located near Pittsburgh, Pennsylvania and are jointly owned by a consortium of energy companies. We purchased our interest from Conectiv, Inc. Keystone and Conemaugh are operated by GPU Generation, Inc., which sold its assets and operating responsibilities to Sithe Energies. Keystone and Conemaugh both consist of two operational coal-fired steam power units with a combined net output of 1,700 MW, four diesel units with a combined net output of 11 MW and an on-site landfill. The units are operated pursuant to a joint ownership participation and operating agreement. Under this agreement each joint owner is entitled to its ownership ratio of the net available output of the facility. All fixed costs are shared in

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proportion to the ownership interests. All variable costs are incurred in proportion to the energy delivered to the owners. Our income statement includes our share of all fixed and variable costs of operating the facilities.

Reorganized NRG

     Our 3.70% and 3.72% share of the Keystone and Conemaugh facilities original cost included in Property, Plant and Equipment and construction in progress at December 6, 2003 was $60 million and $63 million, respectively. The corresponding accumulated depreciation and amortization at December 6, 2003 for Keystone and Conemaugh was $0 million and $0 million, respectively.

     Our 3.70% and 3.72% share of the Keystone and Conemaugh facilities Property, Plant and Equipment and construction in progress as revalued to fair value upon the adoption of the fresh start provisions of SOP 90-7 at December 31, 2003 was $57.9 million and $69.7 million, respectively. The corresponding accumulated depreciation and amortization at December 31, 2003 for Keystone and Conemaugh was $0.2 million and $0.3 million, respectively.

Predecessor Company

     Our 3.70% and 3.72% share of the Keystone and Conemaugh facilities original cost included in Property, Plant and Equipment and construction in progress at December 31, 2002 was $57.9 million and $62.8 million, respectively. The corresponding accumulated depreciation and amortization at December 31, 2002 for Keystone and Conemaugh was $3.5 million and $4.1 million, respectively.

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Note 29 — Unaudited Quarterly Financial Data

     Summarized quarterly unaudited financial data is as follows:

     Summarized quarterly unaudited financial data is as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Reorganized	
 	 	Predecessor Company

	 	NRG

	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	Period	 	 	 	 	 	Period Ended	
 	 	Quarter Ended 2003

	 	Ended 2003
October 1 -	 	Total through	 	2003
December 6 -	
 	 	March 31

	 	June 30

	 	September 30

	 	December 5

	 	December 5, 2003

	 	December 31

	
 	 	(In thousands)	
Operating Revenues	 	$	495,010	 	 	$	441,599	 	 	$	570,760	 	 	$	291,245	 	 	$	1,798,614	 	 	$	138,507	 	
Operating Income/(Loss)	 	 	(12,367	)	 	 	(319,126	)	 	 	(328,112	)	 	 	3,931,700	 	 	 	3,272,095	 	 	 	16,095	 	
Income/(Loss) From Continuing Operations	 	 	(173,545	)	 	 	(509,050	)	 	 	(285,090	)	 	 	3,914,947	 	 	 	2,947,262	 	 	 	11,337	 	
Income/(Loss) on Discontinued Operations net of Income Taxes	 	 	160,913	 	 	 	(99,351	)	 	 	296	 	 	 	(242,675	)	 	 	(180,817	)	 	 	(312	)	
Net Income/(Loss)	 	 	(12,632	)	 	 	(608,401	)	 	 	(284,794	)	 	 	3,672,272	 	 	 	2,766,445	 	 	 	11,025	 	
Weighted Average Number of Common Shares Outstanding — Basic	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	100,000	 	
Income From Continuing Operations per Weighted Average Common Share — Basic	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	$	0.11	 	
Income From Discontinued Operations per Weighted Average Common Share — Basic	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	$	—	 	
Net Income per Weighted Average Common Share — Basic	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	$	0.11	 	
Weighted Average Number of Common Shares Outstanding — Diluted	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	100,060	 	
Income From Continuing Operations per Weighted Average Common Share — Diluted	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	$	0.11	 	
Income From Discontinued Operations per Weighted Average Common Share — Diluted	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	$	—	 	
Net Income per Weighted Average Common Share — Diluted	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	$	0.11	 	

 	 	Predecessor Company

	
 	 	Quarter Ended 2002

	
 	 	March 31

	 	June 30

	 	September 30

	 	December 31

	 	Total Year

	
 	 	 	 	 	 	 	 	 	 	(In thousands)	 	 	 	 	 	 	 	 	
Operating Revenues	 	$	403,394	 	 	$	492,085	 	 	$	591,671	 	 	$	451,399	 	 	$	1,938,549	 	
Operating Income/(Loss)	 	 	15,179	 	 	 	23,590	 	 	 	(2,484,572	)	 	 	59,966	 	 	 	(2,385,837	)	
Loss From Continuing Operations	 	 	(31,036	)	 	 	(29,289	)	 	 	(2,409,772	)	 	 	(321,103	)	 	 	(2,791,200	)	
Income/(Loss) on Discontinued Operations net of Income Taxes	 	 	4,573	 	 	 	(12,063	)	 	 	(645,622	)	 	 	(19,970	)	 	 	(673,082	)	
Net Loss	 	 	(26,463	)	 	 	(41,352	)	 	 	(3,055,394	)	 	 	(341,073	)	 	 	(3,464,282	)	
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Note 30 – Condensed Consolidating Financial Information

     On December 17, 2003 and January 28, 2004, we issued $1.2 billion and $475.0 million, respectively, of 8% Second Priority Senior Secured Notes due on December 15, 2013 (the “Notes”). These notes are guaranteed by each of our current and future wholly owned domestic subsidiaries, or “Guarantor Subsidiaries.” Each of the following Guarantor Subsidiaries fully and unconditionally guarantee the Notes.
 	 	 	
Arthur Kill Power LLC	 	NRG Cabrillo Power Operations Inc.	
Astoria Gas Turbine Power LLC	 	NRG Cadillac Operations Inc.	
Berrians I Gas Turbine Power LLC	 	NRG California Peaker Operations LLC	
Big Cajun II Unit 4 LLC	 	NRG Central U.S. LLC	
Capistrano Cogeneration Company	 	NRG Connecticut Affiliate Services Inc.	
Chickahominy River Energy Corp.	 	NRG Devon Operations Inc.	
Cobee Energy Development LLC	 	NRG Dunkirk Operations Inc.	
Commonwealth Atlantic Power LLC	 	NRG Eastern LLC	
Conemaugh Power LLC	 	NRG El Segundo Operations Inc.	
Connecticut Jet Power LLC	 	NRG Huntley Operations Inc.	
Devon Power LLC	 	NRG International LLC	
Dunkirk Power LLC	 	NRG Kaufman LLC	
Eastern Sierra Energy Company	 	NRG Mesquite LLC	
El Segundo Power II LLC	 	NRG MidAtlantic Affiliate Services Inc.	
Hanover Energy Company	 	NRG MidAtlantic Generating LLC	
Huntley Power LLC .	 	NRG MidAtlantic LLC	
Indian River Operations Inc.	 	NRG Middletown Operations Inc.	
Indian River Power LLC	 	NRG Montville Operations Inc.	
James River Power LLC	 	NRG New Jersey Energy Sales LLC	
Kaufman Cogen LP	 	NRG New Roads Holdings LLC	
Keystone Power LLC	 	NRG North Central Operations Inc.	
Louisiana Generating LLC	 	NRG Northeast Affiliate Services Inc.	
MidAtlantic Generation Holding LLC	 	NRG Northeast Generating LLC	
Middletown Power LLC	 	NRG Norwalk Harbor Operations Inc.	
Montville Power LLC	 	NRG Operating Services, Inc.	
NEO California Power LLC	 	NRG Oswego Harbor Power Operations Inc.	
NEO Chester-Gen LLC	 	NRG Power Marketing Inc.	
NEO Corporation	 	NRG Rocky Road LLC	
NEO Freehold-Gen LLC	 	NRG Saguaro Operations Inc.	
NEO Landfill Gas Holdings Inc.	 	NRG South Central Affiliate Services Inc.	
NEO Landfill Gas Inc.	 	NRG South Central Generating LLC	
NEO Nashville LLC	 	NRG South Central Operations Inc.	
NEO Power Services Inc.	 	NRG West Coast LLC	
NEO Tajiguas LLC	 	NRG Western Affiliate Services Inc.	
Northeast Generation Holding LLC	 	Oswego Harbor Power LLC	
Norwalk Power LLC	 	Saguaro Power LLC	
NRG Affiliate Services Inc.	 	Somerset Operations Inc.	
NRG Arthur Kill Operations Inc.	 	Somerset Power LLC	
NRG Asia-Pacific, Ltd.	 	South Central Generation Holding LLC	
NRG Astoria Gas Turbine Operations ,Inc.	 	Vienna Operations Inc.	
NRG Bayou Cove LLC	 	Vienna Power LLC	
     The non-guarantor subsidiaries, or “Non-Guarantor Subsidiaries,” include all of our foreign subsidiaries and certain domestic subsidiaries. We conduct much of our business through and derive much of our income from our subsidiaries. Therefore, our ability to make required payments with respect to our indebtedness and other obligations depends on the financial results and condition of our subsidiaries and our ability to receive funds from our subsidiaries. Except for NRG Bayou Cove, LLC, which is subject to certain restrictions under our Peaker financing agreements, there are no restrictions on the ability of any of the Guarantor Subsidiaries to transfer funds to us. In addition, there may be restrictions for certain Non-Guarantor Subsidiaries.

     The following condensed consolidating financial information presents the financial information of NRG Energy, the Guarantor Subsidiaries and the Non-Guarantor Subsidiaries in accordance with Rule 3-10 under the Securities and Exchange Commission’s

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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 consists of parent company operations. Guarantor Subsidiaries and Non-Guarantor Subsidiaries of NRG Energy are reported on an equity basis. For companies acquired, the fair values of the assets and liabilities acquired have been presented on a “push-down” accounting basis.

NRG Energy, Inc. and Subsidiaries
Consolidating Statements of Operations
For the Period December 6, 2003 Through December 31, 2003
Reorganized NRG
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantor	 	Non- Guarantor	 	NRG Energy, Inc.	 	Eliminations	 	Consolidated	
 	 	Subsidiaries

	 	Subsidiaries

	 	(Note Issuer)

	 	(1)

	 	Balance

	
 	 	 	 	 	 	 	 	 	 	(In thousands)	 	 	 	 	 	 	 	 	
Operating Revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues from majority-owned operations	 	$	94,459	 	 	$	40,754	 	 	$	3,353	 	 	$	(59	)	 	$	138,507	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cost of majority-owned operations	 	 	64,521	 	 	 	28,793	 	 	 	2,347	 	 	 	(59	)	 	 	95,602	 	
Depreciation and amortization	 	 	7,118	 	 	 	3,931	 	 	 	759	 	 	 	—	 	 	 	11,808	 	
General, administrative and development	 	 	7,171	 	 	 	2,820	 	 	 	2,550	 	 	 	—	 	 	 	12,541	 	
Other charges (credits)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reorganization items	 	 	269	 	 	 	—	 	 	 	2,192	 	 	 	—	 	 	 	2,461	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total operating costs and expenses	 	 	79,079	 	 	 	35,544	 	 	 	7,848	 	 	 	(59	)	 	 	122,412	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Operating Income/(Loss)	 	 	15,380	 	 	 	5,210	 	 	 	(4,495	)	 	 	—	 	 	 	16,095	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Other Income/(Expense)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Minority interest in (earnings)/losses of consolidated subsidiaries	 	 	—	 	 	 	(134	)	 	 	—	 	 	 	—	 	 	 	(134	)	
Equity in earnings of consolidated subsidiaries	 	 	3,266	 	 	 	143	 	 	 	16,482	 	 	 	(19,891	)	 	 	—	 	
Equity in earnings of unconsolidated affiliates	 	 	11,007	 	 	 	1,463	 	 	 	1,051	 	 	 	—	 	 	 	13,521	 	
Other income, net	 	 	43	 	 	 	(24	)	 	 	114	 	 	 	(37	)	 	 	96	 	
Interest expense	 	 	(6,417	)	 	 	(4,719	)	 	 	(7,803	)	 	 	37	 	 	 	(18,902	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total other income/(expense)	 	 	7,899	 	 	 	(3,271	)	 	 	9,844	 	 	 	(19,891	)	 	 	(5,419	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Income/(Loss) From Continuing Operations Before Income Taxes	 	 	23,279	 	 	 	1,939	 	 	 	5,349	 	 	 	(19,891	)	 	 	10,676	 	
Income Tax Expense/(Benefit)	 	 	3,653	 	 	 	1,362	 	 	 	(5,676	)	 	 	—	 	 	 	(661	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Income/(Loss) From Continuing Operations	 	 	19,626	 	 	 	577	 	 	 	11,025	 	 	 	(19,891	)	 	 	11,337	 	
Income/(Loss) on Discontinued Operations, net of Income Taxes	 	 	—	 	 	 	(312	)	 	 	—	 	 	 	—	 	 	 	(312	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Net Income/(Loss)	 	$	19,626	 	 	$	265	 	 	$	11,025	 	 	$	(19,891	)	 	$	11,025	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

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

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NRG Energy, Inc. and Subsidiaries
Consolidating Balance Sheets
December 31, 2003
Reorganized NRG

 	 	Guarantor	 	Non- Guarantor	 	NRG Energy, Inc.	 	Eliminations	 	Consolidated	
 	 	Subsidiaries

	 	Subsidiaries

	 	(Note Issuer)

	 	(1)

	 	Balance

	
 	 	 	 	 	 	 	 	 	 	(In thousands)	 	 	 	 	 	 	 	 	
ASSETS	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	295,509	 	 	$	160,434	 	 	$	95,280	 	 	$	—	 	 	$	551,223	 	
Restricted cash	 	 	4,298	 	 	 	111,769	 	 	 	—	 	 	 	—	 	 	 	116,067	 	
Accounts receivable-trade, net	 	 	120,411	 	 	 	68,151	 	 	 	13,359	 	 	 	—	 	 	 	201,921	 	
Xcel Energy settlement receivable	 	 	—	 	 	 	—	 	 	 	640,000	 	 	 	—	 	 	 	640,000	 	
Current portion of notes receivable — affiliates	 	 	—	 	 	 	—	 	 	 	31,170	 	 	 	(30,970	)	 	 	200	 	
Current portion of notes receivable	 	 	—	 	 	 	64,854	 	 	 	287	 	 	 	—	 	 	 	65,141	 	
Inventory	 	 	164,853	 	 	 	28,839	 	 	 	1,234	 	 	 	—	 	 	 	194,926	 	
Derivative instruments valuation	 	 	772	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	772	 	
Prepayments and other current assets	 	 	86,671	 	 	 	58,200	 	 	 	78,263	 	 	 	(956	)	 	 	222,178	 	
Current deferred income tax	 	 	—	 	 	 	2,998	 	 	 	—	 	 	 	(1,148	)	 	 	1,850	 	
Current assets — discontinued operations	 	 	—	 	 	 	119,561	 	 	 	—	 	 	 	—	 	 	 	119,561	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total current assets	 	 	672,514	 	 	 	614,806	 	 	 	859,593	 	 	 	(33,074	)	 	 	2,113,839	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Property, Plant and Equipment	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
In service	 	 	2,288,280	 	 	 	1,562,048	 	 	 	35,137	 	 	 	—	 	 	 	3,885,465	 	
Under construction	 	 	20,600	 	 	 	118,433	 	 	 	138	 	 	 	—	 	 	 	139,171	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total property, plant and equipment	 	 	2,308,880	 	 	 	1,680,481	 	 	 	35,275	 	 	 	—	 	 	 	4,024,636	 	
Less accumulated depreciation	 	 	(7,118	)	 	 	(3,923	)	 	 	(759	)	 	 	—	 	 	 	(11,800	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Net property, plant and equipment	 	 	2,301,762	 	 	 	1,676,558	 	 	 	34,516	 	 	 	—	 	 	 	4,012,836	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Other Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Investment in subsidiaries	 	 	626,979	 	 	 	—	 	 	 	4,090,996	 	 	 	(4,717,975	)	 	 	—	 	
Equity investments in affiliates	 	 	403,606	 	 	 	322,279	 	 	 	12,113	 	 	 	—	 	 	 	737,998	 	
Notes receivable, less current portion — affiliates	 	 	389,257	 	 	 	120,733	 	 	 	—	 	 	 	(379,838	)	 	 	130,152	 	
Notes receivable, less current portion	 	 	5,678	 	 	 	684,489	 	 	 	1,277	 	 	 	—	 	 	 	691,444	 	
Decommissioning fund investments	 	 	4,809	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	4,809	 	
Intangible assets, net	 	 	411,540	 	 	 	20,821	 	 	 	—	 	 	 	—	 	 	 	432,361	 	
Debt issuance costs, net	 	 	—	 	 	 	—	 	 	 	74,337	 	 	 	—	 	 	 	74,337	 	
Derivative instruments valuation	 	 	—	 	 	 	59,907	 	 	 	—	 	 	 	—	 	 	 	59,907	 	
Non current deferred income tax	 	 	58,586	 	 	 	—	 	 	 	—	 	 	 	(58,586	)	 	 	—	 	
Funded letter of credit	 	 	—	 	 	 	—	 	 	 	250,000	 	 	 	—	 	 	 	250,000	 	
Other assets	 	 	31,220	 	 	 	30,612	 	 	 	56,504	 	 	 	—	 	 	 	118,336	 	
Non-current assets — discontinued operations	 	 	—	 	 	 	618,968	 	 	 	—	 	 	 	—	 	 	 	618,968	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total other assets	 	 	1,931,675	 	 	 	1,857,809	 	 	 	4,485,227	 	 	 	(5,156,399	)	 	 	3,118,312	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total Assets	 	$	4,905,951	 	 	$	4,149,173	 	 	$	5,379,336	 	 	$	(5,189,473	)	 	$	9,244,987	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

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

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NRG Energy, Inc. and Subsidiaries
Consolidating Balance Sheets — (Continued)
December 31, 2003
Reorganized NRG

 	 	Guarantor	 	Non- Guarantor	 	NRG Energy, Inc.	 	Eliminations	 	Consolidated	
 	 	Subsidiaries

	 	Subsidiaries

	 	(Note Issuer)

	 	(1)

	 	Balance

	
 	 	 	 	 	 	 	 	 	 	(In thousands)	 	 	 	 	 	 	 	 	
LIABILITIES AND STOCKHOLDERS’ EQUITY/(DEFICIT)	 	 	 	 	 	 	
Current Liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current portion of long-term debt	 	$	30,121	 	 	$	790,078	 	 	$	12,000	 	 	$	(30,970	)	 	$	801,229	 	
Short-term debt	 	 	—	 	 	 	19,019	 	 	 	—	 	 	 	—	 	 	 	19,019	 	
Accounts payable — trade	 	 	39,378	 	 	 	104,916	 	 	 	14,389	 	 	 	—	 	 	 	158,683	 	
Accounts payable — affiliate	 	 	333,722	 	 	 	(217,207	)	 	 	(102,094	)	 	 	(7,368	)	 	 	7,053	 	
Accrued income tax	 	 	—	 	 	 	—	 	 	 	(74	)	 	 	16,169	 	 	 	16,095	 	
Accrued property, sales and other taxes	 	 	7,232	 	 	 	13,156	 	 	 	1,934	 	 	 	—	 	 	 	22,322	 	
Accrued salaries, benefits and related costs	 	 	9,295	 	 	 	8,949	 	 	 	1,087	 	 	 	—	 	 	 	19,331	 	
Accrued interest	 	 	2,557	 	 	 	2,880	 	 	 	4,501	 	 	 	(956	)	 	 	8,982	 	
Derivative instruments valuation	 	 	429	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	429	 	
Creditor pool obligation	 	 	—	 	 	 	—	 	 	 	540,000	 	 	 	—	 	 	 	540,000	 	
Other bankruptcy settlement	 	 	—	 	 	 	220,000	 	 	 	—	 	 	 	—	 	 	 	220,000	 	
Current deferred income taxes	 	 	509	 	 	 	—	 	 	 	—	 	 	 	(509	)	 	 	—	 	
Other current liabilities	 	 	70,251	 	 	 	13,639	 	 	 	18,971	 	 	 	—	 	 	 	102,861	 	
Current liabilities — discontinued operations	 	 	—	 	 	 	110,177	 	 	 	—	 	 	 	—	 	 	 	110,177	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total current liabilities	 	 	493,494	 	 	 	1,065,607	 	 	 	490,714	 	 	 	(23,634	)	 	 	2,026,181	 	
Other Liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term debt	 	 	10,999	 	 	 	1,333,931	 	 	 	2,446,690	 	 	 	(463,838	)	 	 	3,327,782	 	
Deferred income taxes	 	 	—	 	 	 	152,392	 	 	 	(22,514	)	 	 	19,615	 	 	 	149,493	 	
Postretirement and other benefit obligations	 	 	80,720	 	 	 	13,425	 	 	 	11,801	 	 	 	—	 	 	 	105,946	 	
Derivative instruments valuation	 	 	—	 	 	 	153,503	 	 	 	—	 	 	 	—	 	 	 	153,503	 	
Other long-term obligations	 	 	399,353	 	 	 	66,196	 	 	 	15,389	 	 	 	—	 	 	 	480,938	 	
Non-current liabilities — discontinued operations	 	 	—	 	 	 	558,884	 	 	 	—	 	 	 	—	 	 	 	558,884	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total non-current liabilities	 	 	491,072	 	 	 	2,278,331	 	 	 	2,451,366	 	 	 	(444,223	)	 	 	4,776,546	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total liabilities	 	 	984,566	 	 	 	3,343,938	 	 	 	2,942,080	 	 	 	(467,857	)	 	 	6,802,727	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Minority interest	 	 	—	 	 	 	5,004	 	 	 	—	 	 	 	—	 	 	 	5,004	 	
Commitments and Contingencies	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Stockholders’ Equity/(Deficit)	 	 	3,921,385	 	 	 	800,231	 	 	 	2,437,256	 	 	 	(4,721,616	)	 	 	2,437,256	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total Liabilities and Stockholders’ Equity/(Deficit)	 	$	4,905,951	 	 	$	4,149,173	 	 	$	5,379,336	 	 	$	(5,189,473	)	 	$	9,244,987	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

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

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NRG Energy, Inc. and Subsidiaries
Consolidating Statements of Cash Flows
For the Period December 6, 2003 Through December 31, 2003
Reorganized NRG

 	 	Guarantor	 	Non- Guarantor	 	NRG Energy, Inc.	 	Eliminations	 	Consolidated	
 	 	Subsidiaries

	 	Subsidiaries

	 	(Note Issuer)

	 	(1)

	 	Balance

	
 	 	 	 	 	 	 	 	 	 	(In thousands)	 	 	 	 	 	 	 	 	
Cash Flows from Operating Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income/(loss)	 	$	19,626	 	 	$	265	 	 	$	11,025	 	 	$	(19,891	)	 	$	11,025	 	
Adjustments to reconcile net income/(loss) to net cash provided by operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Distributions in excess of (less than) equity earnings of unconsolidated affiliates	 	 	1,764	 	 	 	(1,894	)	 	 	(17,532	)	 	 	19,891	 	 	 	2,229	 	
Depreciation and amortization	 	 	8,255	 	 	 	4,027	 	 	 	759	 	 	 	—	 	 	 	13,041	 	
Amortization of deferred financing costs	 	 	—	 	 	 	64	 	 	 	453	 	 	 	—	 	 	 	517	 	
Amortization of debt discount/(premium)	 	 	182	 	 	 	1,504	 	 	 	39	 	 	 	—	 	 	 	1,725	 	
Deferred income taxes and investment tax credits	 	 	(487	)	 	 	(212	)	 	 	(4,117	)	 	 	1,554	 	 	 	(3,262	)	
Current tax expense — non cash contribution from members	 	 	4,125	 	 	 	(2,901	)	 	 	—	 	 	 	(1,224	)	 	 	—	 	
Unrealized (gains)/losses on derivatives	 	 	(126	)	 	 	4,960	 	 	 	(1,060	)	 	 	—	 	 	 	3,774	 	
Minority interest	 	 	134	 	 	 	70	 	 	 	—	 	 	 	—	 	 	 	204	 	
Amortization of out of market power contracts	 	 	(16,401	)	 	 	2,970	 	 	 	—	 	 	 	—	 	 	 	(13,431	)	
Cash provided by (used in) changes in certain working capital items, net of effects from acquisitions and dispositions	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Accounts receivable, net	 	 	12,769	 	 	 	5,040	 	 	 	221	 	 	 	—	 	 	 	18,030	 	
Inventory	 	 	3,073	 	 	 	8,041	 	 	 	(60	)	 	 	—	 	 	 	11,054	 	
Prepayments and other current assets	 	 	1,783	 	 	 	1,755	 	 	 	(13,079	)	 	 	37	 	 	 	(9,504	)	
Accounts payable	 	 	(31,810	)	 	 	8,672	 	 	 	(17,789	)	 	 	—	 	 	 	(40,927	)	
Accounts payable-affiliates	 	 	(1,697	)	 	 	(165	)	 	 	2,694	 	 	 	—	 	 	 	832	 	
Accrued income taxes	 	 	—	 	 	 	—	 	 	 	(877	)	 	 	(330	)	 	 	(1,207	)	
Accrued property and sales taxes	 	 	(5,258	)	 	 	622	 	 	 	46	 	 	 	—	 	 	 	(4,590	)	
Accrued salaries, benefits, and related costs	 	 	2,135	 	 	 	3,511	 	 	 	(2,496	)	 	 	—	 	 	 	3,150	 	
Accrued interest	 	 	(42,350	)	 	 	(26,140	)	 	 	4,501	 	 	 	(37	)	 	 	(64,026	)	
Other current liabilities	 	 	(10,814	)	 	 	5,635	 	 	 	(505,688	)	 	 	—	 	 	 	(510,867	)	
Other assets and liabilities	 	 	(162	)	 	 	(6,911	)	 	 	431	 	 	 	—	 	 	 	(6,642	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Net Cash Provided (Used) by Operating Activities	 	 	(55,259	)	 	 	8,913	 	 	 	(542,529	)	 	 	—	 	 	 	(588,875	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Cash Flows from Investing Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Investments in subsidiaries	 	 	—	 	 	 	—	 	 	 	(1,530,536	)	 	 	1,530,536	 	 	 	—	 	
Decrease/(increase) in restricted cash	 	 	343,725	 	 	 	31,547	 	 	 	—	 	 	 	—	 	 	 	375,272	 	
Decrease/(increase) in notes receivable	 	 	1,501	 	 	 	(11,118	)	 	 	(1,170	)	 	 	11,969	 	 	 	1,182	 	
Capital expenditures	 	 	(2,977	)	 	 	(7,583	)	 	 	—	 	 	 	—	 	 	 	(10,560	)	
Investments in projects	 	 	(2,522	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(2,522	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Net Cash Provided (Used) by Investing Activities	 	 	339,727	 	 	 	12,846	 	 	 	(1,531,706	)	 	 	1,542,505	 	 	 	363,372	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Cash Flows from Financing Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Capital contributions from parent	 	 	1,530,536	 	 	 	—	 	 	 	—	 	 	 	(1,530,536	)	 	 	—	 	
Proceeds from issuance of long-term debt	 	 	—	 	 	 	—	 	 	 	2,450,000	 	 	 	—	 	 	 	2,450,000	 	
Deferred debt issuance costs	 	 	—	 	 	 	(5	)	 	 	(74,790	)	 	 	—	 	 	 	(74,795	)	
Funded letter of credit	 	 	—	 	 	 	—	 	 	 	(250,000	)	 	 	—	 	 	 	(250,000	)	
Principal payments on long-term debt	 	 	(1,713,871	)	 	 	(6,092	)	 	 	—	 	 	 	(11,969	)	 	 	(1,731,932	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Net Cash Provided (Used) by Financing Activities	 	 	(183,335	)	 	 	(6,097	)	 	 	2,125,210	 	 	 	(1,542,505	)	 	 	393,273	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Effect of Exchange Rate Changes on Cash and Cash Equivalents	 	 	—	 	 	 	(13,562	)	 	 	—	 	 	 	—	 	 	 	(13,562	)	
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 	 	Guarantor	 	Non- Guarantor	 	NRG Energy, Inc.	 	Eliminations	 	Consolidated	
 	 	Subsidiaries

	 	Subsidiaries

	 	(Note Issuer)

	 	(1)

	 	Balance

	
 	 	 	 	 	 	 	 	 	 	(In thousands)	 	 	 	 	 	 	 	 	
Change in Cash from Discontinued Operations	 	 	—	 	 	 	1,033	 	 	 	—	 	 	 	—	 	 	 	1,033	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Net Increase in Cash and Cash Equivalents	 	 	101,133	 	 	 	3,133	 	 	 	50,975	 	 	 	—	 	 	 	155,241	 	
Cash and Cash Equivalents at Beginning of Period	 	 	194,376	 	 	 	157,301	 	 	 	44,305	 	 	 	—	 	 	 	395,982	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Cash and Cash Equivalents at End of Period	 	$	295,509	 	 	$	160,434	 	 	$	95,280	 	 	$	—	 	 	$	551,223	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

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

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NRG Energy, Inc. and Subsidiaries
Consolidating Statements of Operations
For the Period January 1, 2003 Through December 5, 2003
Predecessor Company
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantor	 	Non- Guarantor	 	NRG Energy, Inc.	 	Eliminations	 	Consolidated	
 	 	Subsidiaries

	 	Subsidiaries

	 	(Note Issuer)

	 	(1)

	 	Balance

	
 	 	 	 	 	 	 	 	 	 	(In thousands)	 	 	 	 	 	 	 	 	
Operating Revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues from majority-owned operations	 	$	1,230,353	 	 	$	522,632	 	 	$	47,054	 	 	$	(1,425	)	 	$	1,798,614	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cost of majority-owned operations	 	 	991,550	 	 	 	334,167	 	 	 	33,239	 	 	 	(1,425	)	 	 	1,357,531	 	
Depreciation and amortization	 	 	130,607	 	 	 	75,087	 	 	 	13,507	 	 	 	—	 	 	 	219,201	 	
General, administrative and development	 	 	65,768	 	 	 	28,860	 	 	 	75,764	 	 	 	—	 	 	 	170,392	 	
Other charges (credits)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Legal settlement	 	 	(9,369	)	 	 	4,000	 	 	 	468,000	 	 	 	—	 	 	 	462,631	 	
Fresh start reporting adjustments	 	 	—	 	 	 	—	 	 	 	(6,570,912	)	 	 	2,452,276	 	 	 	(4,118,636	)	
Fresh start reporting adjustments — subsidiaries	 	 	—	 	 	 	—	 	 	 	2,452,276	 	 	 	(2,452,276	)	 	 	—	 	
Reorganization items	 	 	30,582	 	 	 	16,644	 	 	 	150,599	 	 	 	—	 	 	 	197,825	 	
Restructuring and impairment charges	 	 	247,560	 	 	 	(121,604	)	 	 	111,619	 	 	 	—	 	 	 	237,575	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total operating costs and expenses	 	 	1,456,698	 	 	 	337,154	 	 	 	(3,265,908	)	 	 	(1,425	)	 	 	(1,473,481	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Operating Income/(Loss)	 	 	(226,345	)	 	 	185,478	 	 	 	3,312,962	 	 	 	—	 	 	 	3,272,095	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Other Income (Expense)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Minority interest in (earnings)/losses of consolidated subsidiaries	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Equity in earnings of consolidated subsidiaries	 	 	104,905	 	 	 	—	 	 	 	(18,356	)	 	 	(86,549	)	 	 	—	 	
Equity in earnings of unconsolidated affiliates	 	 	107,254	 	 	 	64,850	 	 	 	(1,203	)	 	 	—	 	 	 	170,901	 	
Write downs and losses on sales of equity method investments	 	 	(16,285	)	 	 	(125,945	)	 	 	(4,894	)	 	 	—	 	 	 	(147,124	)	
Other income, net	 	 	5,087	 	 	 	30,469	 	 	 	(15,429	)	 	 	(919	)	 	 	19,208	 	
Interest expense	 	 	(135,837	)	 	 	(83,135	)	 	 	(111,836	)	 	 	919	 	 	 	(329,889	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total other income/(expense)	 	 	65,124	 	 	 	(113,761	)	 	 	(151,718	)	 	 	(86,549	)	 	 	(286,904	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Income/(Loss) From Continuing Operations Before Income Taxes	 	 	(161,221	)	 	 	71,717	 	 	 	3,161,244	 	 	 	(86,549	)	 	 	2,985,191	 	
Income Tax Expense/(Benefit)	 	 	(107,292	)	 	 	(10,791	)	 	 	156,012	 	 	 	—	 	 	 	37,929	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Income/(Loss) From Continuing Operations	 	 	(53,929	)	 	 	82,508	 	 	 	3,005,232	 	 	 	(86,549	)	 	 	2,947,262	 	
Income/(Loss) on Discontinued Operations, net of Income Taxes	 	 	(25,536	)	 	 	83,506	 	 	 	(238,787	)	 	 	—	 	 	 	(180,817	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Net Income/(Loss)	 	$	(79,465	)	 	$	166,014	 	 	$	2,766,445	 	 	$	(86,549	)	 	$	2,766,445	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

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

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NRG Energy, Inc. and Subsidiaries
Consolidating Balance Sheets
December 6, 2003
Reorganized Company
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	NRG Energy,	 	 	 	 	
 	 	Guarantor	 	Non- Guarantor	 	Inc. (Note	 	Eliminations	 	Consolidated	
 	 	Subsidiaries

	 	Subsidiaries

	 	Issuer)

	 	(1)

	 	Balance

	
 	 	 	 	 	 	 	 	 	 	(In thousands)	 	 	 	 	 	 	 	 	
ASSETS	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	194,376	 	 	$	157,301	 	 	$	44,305	 	 	$	—	 	 	$	395,982	 	
Restricted cash	 	 	348,023	 	 	 	145,024	 	 	 	—	 	 	 	—	 	 	 	493,047	 	
Accounts receivable-trade, net	 	 	133,180	 	 	 	66,719	 	 	 	13,580	 	 	 	—	 	 	 	213,479	 	
Xcel Energy settlement receivable	 	 	—	 	 	 	—	 	 	 	640,000	 	 	 	—	 	 	 	640,000	 	
Current portion of notes receivable	 	 	1,500	 	 	 	311,559	 	 	 	30,274	 	 	 	(276,705	)	 	 	66,628	 	
Inventory	 	 	167,926	 	 	 	27,136	 	 	 	1,174	 	 	 	—	 	 	 	196,236	 	
Derivative instruments valuation	 	 	161	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	161	 	
Prepayments and other current assets	 	 	88,454	 	 	 	57,878	 	 	 	65,184	 	 	 	(919	)	 	 	210,597	 	
Current deferred income tax	 	 	—	 	 	 	2,822	 	 	 	—	 	 	 	(2,822	)	 	 	—	 	
Current assets — discontinued operations	 	 	(1,075	)	 	 	129,003	 	 	 	(1,408	)	 	 	—	 	 	 	126,520	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total current assets	 	 	932,545	 	 	 	897,442	 	 	 	793,109	 	 	 	(280,446	)	 	 	2,342,650	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Property, Plant and Equipment	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
In service	 	 	2,288,119	 	 	 	1,553,540	 	 	 	35,136	 	 	 	—	 	 	 	3,876,795	 	
Under construction	 	 	17,888	 	 	 	113,977	 	 	 	138	 	 	 	—	 	 	 	132,003	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total property, plant and equipment	 	 	2,306,007	 	 	 	1,667,517	 	 	 	35,274	 	 	 	—	 	 	 	4,008,798	 	
Less accumulated depreciation	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Net property, plant and equipment	 	 	2,306,007	 	 	 	1,667,517	 	 	 	35,274	 	 	 	—	 	 	 	4,008,798	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Other Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Investment in subsidiaries	 	 	604,809	 	 	 	—	 	 	 	2,327,927	 	 	 	(2,932,736	)	 	 	—	 	
Equity investments in affiliates	 	 	405,860	 	 	 	316,509	 	 	 	11,493	 	 	 	—	 	 	 	733,862	 	
Notes receivable, less current
portion — affiliates	 	 	9,419	 	 	 	322,366	 	 	 	—	 	 	 	(206,134	)	 	 	125,651	 	
Notes receivable, less current portion	 	 	385,517	 	 	 	204,124	 	 	 	1,290	 	 	 	84,000	 	 	 	674,931	 	
Decommissioning fund investments	 	 	4,787	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	4,787	 	
Deferred income taxes	 	 	57,887	 	 	 	—	 	 	 	—	 	 	 	(57,887	)	 	 	—	 	
Intangible assets, net	 	 	414,258	 	 	 	70,410	 	 	 	—	 	 	 	—	 	 	 	484,668	 	
Derivative instruments valuation	 	 	—	 	 	 	66,442	 	 	 	—	 	 	 	—	 	 	 	66,442	 	
Other assets	 	 	31,215	 	 	 	25,171	 	 	 	56,504	 	 	 	—	 	 	 	112,890	 	
Non-current assets — discontinued operations	 	 	—	 	 	 	612,650	 	 	 	—	 	 	 	—	 	 	 	612,650	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total other assets	 	 	1,913,752	 	 	 	1,617,672	 	 	 	2,397,214	 	 	 	(3,112,757	)	 	 	2,815,881	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total Assets	 	$	5,152,304	 	 	$	4,182,631	 	 	$	3,225,597	 	 	$	(3,393,203	)	 	$	9,167,329	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

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

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Table of Contents

NRG Energy, Inc. and Subsidiaries
Consolidating Balance Sheets — (Continued)
December 6, 2003
Reorganized Company
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	NRG Energy,	 	 	 	 	
 	 	Guarantor	 	Non- Guarantor	 	Inc.	 	Eliminations	 	Consolidated	
 	 	Subsidiaries

	 	Subsidiaries

	 	(Note Issuer)

	 	(1)

	 	Balance

	
 	 	(In thousands)	
LIABILITIES AND STOCKHOLDERS’ EQUITY/(DEFICIT)	 	 	 	 	 	 	
Current Liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current portion of long-term debt	 	$	1,743,810	 	 	$	782,944	 	 	$	—	 	 	$	(30,000	)	 	$	2,496,754	 	
Short-term debt	 	 	—	 	 	 	18,645	 	 	 	—	 	 	 	—	 	 	 	18,645	 	
Accounts payable — trade	 	 	71,188	 	 	 	99,105	 	 	 	32,178	 	 	 	—	 	 	 	202,471	 	
Accounts payable — affiliate	 	 	334,354	 	 	 	(204,841	)	 	 	(105,157	)	 	 	(7,368	)	 	 	16,988	 	
Accrued income tax	 	 	—	 	 	 	—	 	 	 	803	 	 	 	15,628	 	 	 	16,431	 	
Accrued property, sales and other taxes	 	 	12,490	 	 	 	13,436	 	 	 	1,888	 	 	 	—	 	 	 	27,814	 	
Accrued salaries, benefits and related costs	 	 	8,209	 	 	 	4,587	 	 	 	3,923	 	 	 	—	 	 	 	16,719	 	
Accrued interest	 	 	44,907	 	 	 	31,785	 	 	 	—	 	 	 	(919	)	 	 	75,773	 	
Derivative instruments valuation	 	 	95	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	95	 	
Creditor pool obligation	 	 	3,360	 	 	 	—	 	 	 	1,036,640	 	 	 	—	 	 	 	1,040,000	 	
Other bankruptcy settlement	 	 	—	 	 	 	220,000	 	 	 	—	 	 	 	—	 	 	 	220,000	 	
Current deferred income taxes	 	 	498	 	 	 	—	 	 	 	—	 	 	 	(498	)	 	 	—	 	
Other current liabilities	 	 	92,805	 	 	 	15,951	 	 	 	28,019	 	 	 	—	 	 	 	136,775	 	
Current liabilities — discontinued operations	 	 	—	 	 	 	108,975	 	 	 	—	 	 	 	—	 	 	 	108,975	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total current liabilities	 	 	2,311,716	 	 	 	1,090,587	 	 	 	998,294	 	 	 	(23,157	)	 	 	4,377,440	 	
Other Liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term debt	 	 	10,999	 	 	 	1,312,875	 	 	 	8,651	 	 	 	(452,839	)	 	 	879,686	 	
Deferred income taxes	 	 	—	 	 	 	149,172	 	 	 	(212,196	)	 	 	207,712	 	 	 	144,688	 	
Postretirement and other benefit obligations	 	 	79,671	 	 	 	13,580	 	 	 	11,461	 	 	 	—	 	 	 	104,712	 	
Derivative instruments valuation	 	 	—	 	 	 	155,709	 	 	 	—	 	 	 	—	 	 	 	155,709	 	
Other long-term obligations	 	 	402,362	 	 	 	118,933	 	 	 	15,387	 	 	 	—	 	 	 	536,682	 	
Non-current liabilities — discontinued operations	 	 	—	 	 	 	559,560	 	 	 	—	 	 	 	—	 	 	 	559,560	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total non-current liabilities	 	 	493,032	 	 	 	2,309,829	 	 	 	(176,697	)	 	 	(245,127	)	 	 	2,381,037	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total liabilities	 	 	2,804,748	 	 	 	3,400,416	 	 	 	821,597	 	 	 	(268,284	)	 	 	6,758,477	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Minority interest	 	 	—	 	 	 	4,852	 	 	 	—	 	 	 	—	 	 	 	4,852	 	
Commitments and Contingencies	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Stockholders’ Equity/(Deficit)	 	 	2,347,556	 	 	 	777,363	 	 	 	2,404,000	 	 	 	(3,124,919	)	 	 	2,404,000	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total Liabilities and Stockholders’ Equity/(Deficit)	 	$	5,152,304	 	 	$	4,182,631	 	 	$	3,225,597	 	 	$	(3,393,203	)	 	$	9,167,329	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

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

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NRG Energy, Inc. and Subsidiaries
Consolidating Statements of Cash Flow
For the Period January 1, 2003 Through December 5, 2003
Predecessor Company
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	NRG Energy,	 	 	 	 	
 	 	Guarantor	 	Non- Guarantor	 	Inc.	 	Eliminations	 	Consolidated	
 	 	Subsidiaries

	 	Subsidiaries

	 	(Note Issuer)

	 	(1)

	 	Balance

	
 	 	 	 	 	 	 	 	 	 	(In thousands)	 	 	 	 	 	 	 	 	
Cash Flows from Operating Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income/(loss)	 	$	(79,465	)	 	$	166,014	 	 	$	2,766,445	 	 	$	(86,549	)	 	$	2,766,445	 	
Adjustments to reconcile net income/(loss) to net cash provided by operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Distributions in excess of (less than) equity earnings of unconsolidated affiliates	 	 	(95,360	)	 	 	(53,400	)	 	 	20,739	 	 	 	86,549	 	 	 	(41,472	)	
Depreciation and amortization	 	 	131,399	 	 	 	111,794	 	 	 	13,507	 	 	 	—	 	 	 	256,700	 	
Amortization of deferred financing costs	 	 	6,676	 	 	 	7,016	 	 	 	3,948	 	 	 	—	 	 	 	17,640	 	
Write downs and losses on sales of equity method investments	 	 	16,284	 	 	 	130,654	 	 	 	—	 	 	 	—	 	 	 	146,938	 	
Deferred income taxes and investment tax credits	 	 	(123,237	)	 	 	(36,015	)	 	 	181,544	 	 	 	(24,185	)	 	 	(1,893	)	
Current tax expense — non cash contribution from members	 	 	(17,149	)	 	 	(54,148	)	 	 	—	 	 	 	71,297	 	 	 	—	 	
Unrealized (gains)/losses on derivatives	 	 	(12,246	)	 	 	(75,310	)	 	 	29,540	 	 	 	23,400	 	 	 	(34,616	)	
Minority interest	 	 	—	 	 	 	2,177	 	 	 	—	 	 	 	—	 	 	 	2,177	 	
Restructuring & impairment charges	 	 	273,138	 	 	 	93,516	 	 	 	41,723	 	 	 	—	 	 	 	408,377	 	
Fresh start reporting adjustments	 	 	—	 	 	 	—	 	 	 	(3,895,541	)	 	 	—	 	 	 	(3,895,541	)	
Gain on sale of discontinued operations	 	 	3,180	 	 	 	(198,666	)	 	 	9,155	 	 	 	—	 	 	 	(186,331	)	
Cash provided by (used in) changes in certain working capital items, net of effects from acquisitions and dispositions	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Accounts receivable, net	 	 	59,168	 	 	 	(5,552	)	 	 	(25,355	)	 	 	—	 	 	 	28,261	 	
Inventory	 	 	25,713	 	 	 	(14,512	)	 	 	2,927	 	 	 	—	 	 	 	14,128	 	
Prepayments and other current assets	 	 	(30,388	)	 	 	8,599	 	 	 	(15,942	)	 	 	919	 	 	 	(36,812	)	
Accounts payable	 	 	116,452	 	 	 	(57,004	)	 	 	634,215	 	 	 	—	 	 	 	693,663	 	
Accounts payable-affiliates	 	 	189,204	 	 	 	(52,324	)	 	 	(20,346	)	 	 	(161,551	)	 	 	(45,017	)	
Accrued income taxes	 	 	—	 	 	 	—	 	 	 	68,356	 	 	 	(47,112	)	 	 	21,244	 	
Accrued property and sales taxes	 	 	(2,015	)	 	 	(625	)	 	 	(519	)	 	 	—	 	 	 	(3,159	)	
Accrued salaries, benefits, and related costs	 	 	(41,037	)	 	 	92,331	 	 	 	(10,604	)	 	 	—	 	 	 	40,690	 	
Accrued interest	 	 	(14,865	)	 	 	54,773	 	 	 	119,592	 	 	 	(919	)	 	 	158,581	 	
Other current liabilities	 	 	29,631	 	 	 	46,438	 	 	 	(98,866	)	 	 	—	 	 	 	(22,797	)	
Other assets and liabilities	 	 	15,940	 	 	 	(68,051	)	 	 	3,414	 	 	 	—	 	 	 	(48,697	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Net Cash Provided (Used) by Operating Activities	 	 	451,023	 	 	 	97,705	 	 	 	(172,068	)	 	 	(138,151	)	 	 	238,509	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Cash Flows from Investing Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Investment in subsidiaries	 	 	—	 	 	 	—	 	 	 	129,351	 	 	 	(129,351	)	 	 	—	 	
Proceeds from sale of discontinued operations	 	 	—	 	 	 	18,612	 	 	 	—	 	 	 	—	 	 	 	18,612	 	
Proceeds from sale of investments	 	 	—	 	 	 	107,174	 	 	 	—	 	 	 	—	 	 	 	107,174	 	
Proceeds from sale of turbines	 	 	—	 	 	 	—	 	 	 	70,717	 	 	 	—	 	 	 	70,717	 	
(Increase) in trust funds	 	 	(13,971	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(13,971	)	
Decrease/(increase) in restricted cash	 	 	(197,692	)	 	 	(54,803	)	 	 	—	 	 	 	—	 	 	 	(252,495	)	
Decrease/(increase) in notes receivable	 	 	98,064	 	 	 	42,493	 	 	 	285	 	 	 	(142,495	)	 	 	(1,653	)	
Capital expenditures	 	 	(55,833	)	 	 	(6,450	)	 	 	(51,219	)	 	 	—	 	 	 	(113,502	)	
Investments in projects	 	 	(3,672	)	 	 	(5,259	)	 	 	8,370	 	 	 	—	 	 	 	(561	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Net Cash Provided (Used) by Investing Activities	 	 	(173,104	)	 	 	101,767	 	 	 	157,504	 	 	 	(271,846	)	 	 	(185,679	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Cash Flows from Financing Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Capital contributions from parent	 	 	(135,251	)	 	 	(132,251	)	 	 	—	 	 	 	267,502	 	 	 	—	 	
Proceeds from issuance of long-term debt	 	 	—	 	 	 	39,988	 	 	 	—	 	 	 	—	 	 	 	39,988	 	
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Table of Contents
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	NRG Energy,	 	 	 	 	
 	 	Guarantor	 	Non- Guarantor	 	Inc.	 	Eliminations	 	Consolidated	
 	 	Subsidiaries

	 	Subsidiaries

	 	(Note Issuer)

	 	(1)

	 	Balance

	
 	 	 	 	 	 	 	 	 	 	(In thousands)	 	 	 	 	 	 	 	 	
Deferred debt issuance costs	 	 	(7,640	)	 	 	(447	)	 	 	(10,453	)	 	 	—	 	 	 	(18,540	)	
Principal payments on long-term debt	 	 	(4,055	)	 	 	(189,832	)	 	 	—	 	 	 	142,495	 	 	 	(51,392	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Net Cash Provided (Used) by Financing Activities	 	 	(146,946	)	 	 	(282,542	)	 	 	(10,453	)	 	 	409,997	 	 	 	(29,944	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Effect of Exchange Rate Changes on Cash and Cash Equivalents	 	 	—	 	 	 	(22,276	)	 	 	—	 	 	 	—	 	 	 	(22,276	)	
Change in Cash from Discontinued Operations	 	 	—	 	 	 	34,512	 	 	 	—	 	 	 	—	 	 	 	34,512	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Net Increase in Cash and Cash Equivalents	 	 	130,973	 	 	 	(70,834	)	 	 	(25,017	)	 	 	—	 	 	 	35,122	 	
Cash and Cash Equivalents at Beginning of Period	 	 	63,403	 	 	 	228,135	 	 	 	69,322	 	 	 	—	 	 	 	360,860	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Cash and Cash Equivalents at End of Period	 	$	194,376	 	 	$	157,301	 	 	$	44,305	 	 	$	—	 	 	$	395,982	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

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

132

Table of Contents

NRG Energy, Inc. and Subsidiaries
Consolidating Statements of Operations
For the Year Ended December 31, 2002
Predecessor Company
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantor	 	Non- Guarantor	 	NRG Energy, Inc.	 	Eliminations	 	Consolidated	
 	 	Subsidiaries

	 	Subsidiaries

	 	(Note Issuer)

	 	(1)

	 	Balance

	
 	 	 	 	 	 	 	 	 	 	(In thousands)	 	 	 	 	 	 	 	 	
Operating Revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues from majority-owned operations	 	$	1,376,657	 	 	$	510,619	 	 	$	55,492	 	 	$	(4,219	)	 	$	1,938,549	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cost of majority-owned operations	 	 	919,292	 	 	 	346,599	 	 	 	72,750	 	 	 	(4,378	)	 	 	1,334,263	 	
Depreciation and amortization	 	 	126,625	 	 	 	70,267	 	 	 	11,257	 	 	 	—	 	 	 	208,149	 	
General, administrative and development	 	 	49,772	 	 	 	53,301	 	 	 	115,682	 	 	 	159	 	 	 	218,914	 	
Other charges (credits)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Restructuring and impairment charges	 	 	108,236	 	 	 	2,091,845	 	 	 	362,979	 	 	 	—	 	 	 	2,563,060	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total operating costs and expenses	 	 	1,203,925	 	 	 	2,562,012	 	 	 	562,668	 	 	 	(4,219	)	 	 	4,324,386	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Operating Income/(Loss)	 	 	172,732	 	 	 	(2,051,393	)	 	 	(507,176	)	 	 	—	 	 	 	(2,385,837	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Other Income (Expense)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Minority interest in (earnings)/losses of consolidated subsidiaries	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Equity in earnings of consolidated subsidiaries	 	 	(690,627	)	 	 	(454	)	 	 	(2,944,968	)	 	 	3,636,049	 	 	 	—	 	
Equity in earnings of unconsolidated affiliates	 	 	17,786	 	 	 	50,398	 	 	 	812	 	 	 	—	 	 	 	68,996	 	
Write downs and losses on sales of equity method investments	 	 	(16,255	)	 	 	(182,035	)	 	 	(2,182	)	 	 	—	 	 	 	(200,472	)	
Other income, net	 	 	9,648	 	 	 	9,220	 	 	 	(4,127	)	 	 	(3,311	)	 	 	11,430	 	
Interest expense	 	 	(142,775	)	 	 	(115,743	)	 	 	(196,977	)	 	 	3,311	 	 	 	(452,184	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total other income/(expense)	 	 	(822,223	)	 	 	(238,614	)	 	 	(3,147,442	)	 	 	3,636,049	 	 	 	(572,230	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Income/(Loss) From Continuing Operations Before Income Taxes	 	 	(649,491	)	 	 	(2,290,007	)	 	 	(3,654,618	)	 	 	3,636,049	 	 	 	(2,958,067	)	
Income Tax Expense/(Benefit)	 	 	(1,905	)	 	 	25,374	 	 	 	(190,336	)	 	 	—	 	 	 	(166,867	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Income/(Loss) From Continuing Operations	 	 	(647,586	)	 	 	(2,315,381	)	 	 	(3,464,282	)	 	 	3,636,049	 	 	 	(2,791,200	)	
Income/(Loss) on Discontinued	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operations, net of Income Taxes	 	 	(24,668	)	 	 	(648,414	)	 	 	—	 	 	 	—	 	 	 	(673,082	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Net Income/(Loss)	 	$	(672,254	)	 	$	(2,963,795	)	 	$	(3,464,282	)	 	$	3,636,049	 	 	$	(3,464,282	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

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

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NRG Energy, Inc. and Subsidiaries
Consolidating Balance Sheets
December 31, 2002
Predecessor Company
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	NRG Energy,	 	 	 	 	
 	 	Guarantor	 	Non- Guarantor	 	Inc.	 	Eliminations	 	Consolidated	
 	 	Subsidiaries

	 	Subsidiaries

	 	(Note Issuer)

	 	(1)

	 	Balance

	
 	 	 	 	 	 	 	 	 	 	(In thousands)	 	 	 	 	 	 	 	 	
ASSETS	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	63,403	 	 	$	228,136	 	 	$	69,322	 	 	$	—	 	 	$	360,861	 	
Restricted cash	 	 	150,331	 	 	 	61,635	 	 	 	—	 	 	 	—	 	 	 	211,966	 	
Accounts receivable-trade, net	 	 	192,060	 	 	 	60,108	 	 	 	5,452	 	 	 	—	 	 	 	257,620	 	
Current portion of notes receivable — affiliates	 	 	—	 	 	 	2,442	 	 	 	—	 	 	 	—	 	 	 	2,442	 	
Current portion of notes receivable	 	 	479,284	 	 	 	84,319	 	 	 	—	 	 	 	(511,334	)	 	 	52,269	 	
Income tax receivable	 	 	—	 	 	 	—	 	 	 	68,356	 	 	 	(59,968	)	 	 	8,388	 	
Inventory	 	 	226,951	 	 	 	22,485	 	 	 	4,576	 	 	 	—	 	 	 	254,012	 	
Derivative instruments valuation	 	 	28,761	 	 	 	—	 	 	 	30	 	 	 	—	 	 	 	28,791	 	
Prepayments and other current assets	 	 	76,664	 	 	 	27,112	 	 	 	29,940	 	 	 	—	 	 	 	133,716	 	
Current deferred income tax	 	 	12,359	 	 	 	(2,557	)	 	 	—	 	 	 	(9,802	)	 	 	—	 	
Current assets — discontinued operations	 	 	(1,370	)	 	 	239,802	 	 	 	—	 	 	 	—	 	 	 	238,432	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total current assets	 	 	1,228,443	 	 	 	723,482	 	 	 	177,676	 	 	 	(581,104	)	 	 	1,548,497	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Property, Plant and Equipment	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
In service	 	 	3,417,066	 	 	 	2,184,612	 	 	 	92,306	 	 	 	—	 	 	 	5,693,984	 	
Under construction	 	 	64,393	 	 	 	486,560	 	 	 	60,224	 	 	 	—	 	 	 	611,177	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total property, plant and equipment	 	 	3,481,459	 	 	 	2,671,172	 	 	 	152,530	 	 	 	—	 	 	 	6,305,161	 	
Less accumulated depreciation	 	 	(288,456	)	 	 	(168,902	)	 	 	(44,603	)	 	 	—	 	 	 	(501,961	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Net property, plant and equipment	 	 	3,193,003	 	 	 	2,502,270	 	 	 	107,927	 	 	 	—	 	 	 	5,803,200	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Other Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Investment in subsidiaries	 	 	111,400	 	 	 	—	 	 	 	2,535,759	 	 	 	(2,647,159	)	 	 	—	 	
Equity investments in affiliates	 	 	530,829	 	 	 	320,716	 	 	 	32,718	 	 	 	—	 	 	 	884,263	 	
Notes receivable, less current portion — affiliates	 	 	9,538	 	 	 	142,014	 	 	 	—	 	 	 	—	 	 	 	151,552	 	
Notes receivable, less current portion	 	 	5,678	 	 	 	776,905	 	 	 	31,849	 	 	 	(30,000	)	 	 	784,432	 	
Decommissioning fund investments	 	 	4,617	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	4,617	 	
Intangible assets, net	 	 	25,349	 	 	 	48,634	 	 	 	1,148	 	 	 	—	 	 	 	75,131	 	
Debt issuance costs, net	 	 	24,582	 	 	 	81,582	 	 	 	22,996	 	 	 	—	 	 	 	129,160	 	
Derivative instruments valuation	 	 	9,601	 	 	 	48,460	 	 	 	32,705	 	 	 	—	 	 	 	90,766	 	
Other assets	 	 	4,893	 	 	 	4,087	 	 	 	8,519	 	 	 	—	 	 	 	17,499	 	
Non-current assets — discontinued operations	 	 	30,421	 	 	 	1,377,313	 	 	 	—	 	 	 	—	 	 	 	1,407,734	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total other assets	 	 	756,908	 	 	 	2,799,711	 	 	 	2,665,694	 	 	 	(2,677,159	)	 	 	3,545,154	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total Assets	 	$	5,178,354	 	 	$	6,025,463	 	 	$	2,951,297	 	 	$	(3,258,263	)	 	$	10,896,851	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

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

134

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NRG Energy, Inc. and Subsidiaries
Consolidating Balance Sheets — (Continued)
December 31, 2002
Predecessor Company
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	NRG Energy,	 	 	 	 	
 	 	Guarantor	 	Non- Guarantor	 	Inc.	 	Eliminations	 	Consolidated	
 	 	Subsidiaries

	 	Subsidiaries

	 	(Note Issuer)

	 	(1)

	 	Balance

	
 	 	 	 	 	 	 	 	 	 	(In thousands)	 	 	 	 	 	 	 	 	
LIABILITIES AND STOCKHOLDERS’ EQUITY/(DEFICIT)	 	 	 	 	 	 	
Current Liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current portion of long-term debt	 	$	1,716,451	 	 	$	2,286,403	 	 	$	2,998,280	 	 	$	—	 	 	$	7,001,134	 	
Revolving line of credit	 	 	—	 	 	 	—	 	 	 	1,000,000	 	 	 	—	 	 	 	1,000,000	 	
Short-term debt	 	 	—	 	 	 	15,849	 	 	 	14,215	 	 	 	—	 	 	 	30,064	 	
Accounts payable — trade	 	 	85,438	 	 	 	301,040	 	 	 	153,693	 	 	 	—	 	 	 	540,171	 	
Accounts payable — affiliate	 	 	486,161	 	 	 	411,099	 	 	 	(831,931	)	 	 	(7,368	)	 	 	57,961	 	
Accrued income tax	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Accrued property, sales and other taxes	 	 	2,015	 	 	 	21,737	 	 	 	519	 	 	 	—	 	 	 	24,271	 	
Accrued salaries, benefits and related costs	 	 	5,709	 	 	 	7,950	 	 	 	3,185	 	 	 	—	 	 	 	16,844	 	
Accrued interest	 	 	59,674	 	 	 	37,261	 	 	 	180,181	 	 	 	—	 	 	 	277,116	 	
Derivative instruments valuation	 	 	13,334	 	 	 	13	 	 	 	92	 	 	 	—	 	 	 	13,439	 	
Current deferred income taxes	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Other current liabilities	 	 	8,737	 	 	 	12,876	 	 	 	83,728	 	 	 	—	 	 	 	105,341	 	
Current liabilities — discontinued operations	 	 	8,417	 	 	 	754,653	 	 	 	—	 	 	 	—	 	 	 	763,070	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total current liabilities	 	 	2,385,936	 	 	 	3,848,881	 	 	 	3,601,962	 	 	 	(7,368	)	 	 	9,829,411	 	
Other Liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term debt	 	 	65,050	 	 	 	1,341,798	 	 	 	—	 	 	 	(625,334	)	 	 	781,514	 	
Deferred income taxes	 	 	(137,308	) 	 	 	(111,446	)	 	 	(4,424	)	 	 	328,064	 	 	 	74,886	 	
Postretirement and other benefit obligations	 	 	35,678	 	 	 	11,479	 	 	 	20,338	 	 	 	—	 	 	 	67,495	 	
Derivative instruments valuation	 	 	9,467	 	 	 	81,311	 	 	 	261	 	 	 	—	 	 	 	91,039	 	
Other long-term obligations	 	 	38,208	 	 	 	78,027	 	 	 	29,359	 	 	 	—	 	 	 	145,594	 	
Non-current liabilities — discontinued operations	 	 	—	 	 	 	602,600	 	 	 	—	 	 	 	—	 	 	 	602,600	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total non-current liabilities	 	 	11,095	 	 	 	2,003,769	 	 	 	45,534	 	 	 	(297,270	)	 	 	1,763,128	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total liabilities	 	 	2,397,031	 	 	 	5,852,650	 	 	 	3,647,496	 	 	 	(304,638	)	 	 	11,592,539	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Minority interest	 	 	—	 	 	 	511	 	 	 	—	 	 	 	—	 	 	 	511	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Commitments and Contingencies	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Stockholders’ Equity/(Deficit)	 	 	2,781,323	 	 	 	172,302	 	 	 	(696,199	)	 	 	(2,953,625	)	 	 	(696,199	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total Liabilities and Stockholders’ Equity/(Deficit)	 	$	5,178,354	 	 	$	6,025,463	 	 	$	2,951,297	 	 	$	(3,258,263	)	 	$	10,896,851	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

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

135

Table of Contents

NRG Energy, Inc. and Subsidiaries
Consolidating Statements of Cash Flows
For the Year Ended December 31, 2002
Predecessor Company
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	NRG Energy,	 	 	 	 	 	 	 	 	
 	 	Guarantor	 	Non- Guarantor	 	Inc.	 	Eliminations	 	Consolidated	 	 	 	 	
 	 	Subsidiaries

	 	Subsidiaries

	 	(Note Issuer)

	 	(1)

	 	Balance

	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	(In thousands)	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flows from Operating Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income/(loss)	 	$	(672,254	)	 	$	(2,963,795	)	 	$	(3,464,282	)	 	$	3,636,049	 	 	$	(3,464,282	)	 	 	 	 	
Adjustments to reconcile net income/(loss) to net cash provided by operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Distributions in excess of (less than) equity earnings of unconsolidated affiliates	 	 	689,451	 	 	 	(19,810	)	 	 	2,944,156	 	 	 	(3,636,049	)	 	 	(22,252	)	 	 	 	 	
Depreciation and amortization	 	 	131,876	 	 	 	143,491	 	 	 	11,256	 	 	 	—	 	 	 	286,623	 	 	 	 	 	
Amortization of deferred financing costs	 	 	3,450	 	 	 	13,046	 	 	 	11,871	 	 	 	—	 	 	 	28,367	 	 	 	 	 	
Write downs and losses on sales of equity method Investments	 	 	11,975	 	 	 	182,035	 	 	 	2,182	 	 	 	—	 	 	 	196,192	 	 	 	 	 	
Deferred income taxes and investment tax credits	 	 	(44,442	)	 	 	(9,847	)	 	 	(130,273	)	 	 	(45,572	) 	 	 	(230,134	)	 	 	 	 	
Current tax expense — non cash contribution from members	 	 	3,874	 	 	 	(27,477	) 	 	 	—	 	 	 	23,603	 	 	 	—	 	 	 	 	 	
Unrealized (gains)/losses on derivatives	 	 	(18,439	)	 	 	47,422	 	 	 	(31,726	)	 	 	—	 	 	 	(2,743	)	 	 	 	 	
Minority interest	 	 	—	 	 	 	(19,325	)	 	 	—	 	 	 	—	 	 	 	(19,325	)	 	 	 	 	
Amortization of out of market power contracts	 	 	(89,415	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(89,415	)	 	 	 	 	
Restructuring & impairment charges	 	 	109,207	 	 	 	2,760,390	 	 	 	274,912	 	 	 	—	 	 	 	3,144,509	 	 	 	 	 	
Gain on sale of discontinued operations	 	 	—	 	 	 	(2,814	)	 	 	—	 	 	 	—	 	 	 	(2,814	)	 	 	 	 	
Cash provided by (used in) changes in certain working capital items, net of effects from acquisitions and dispositions	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Accounts receivable, net	 	 	(72,106	)	 	 	29,883	 	 	 	26,736	 	 	 	—	 	 	 	(15,487	)	 	 	 	 	
Accounts receivable-affiliates	 	 	1,100	 	 	 	1,171	 	 	 	—	 	 	 	—	 	 	 	2,271	 	 	 	 	 	
Inventory	 	 	49,795	 	 	 	(7,185	)	 	 	(14	)	 	 	—	 	 	 	42,596	 	 	 	 	 	
Prepayments and other current assets	 	 	(44,999	)	 	 	13,412	 	 	 	(26,781	)	 	 	—	 	 	 	(58,368	)	 	 	 	 	
Accounts payable	 	 	(38,789	)	 	 	180,682	 	 	 	137,007	 	 	 	—	 	 	 	278,900	 	 	 	 	 	
Accounts payable-affiliates	 	 	358,032	 	 	 	417,072	 	 	 	(728,193	)	 	 	138	 	 	 	47,049	 	 	 	 	 	
Accrued income taxes	 	 	—	 	 	 	—	 	 	 	22,168	 	 	 	21,969	 	 	 	44,137	 	 	 	 	 	
Accrued property and sales taxes	 	 	(7,678	)	 	 	34,634	 	 	 	525	 	 	 	—	 	 	 	27,481	 	 	 	 	 	
Accrued salaries, benefits, and related costs	 	 	(8,253	)	 	 	2,708	 	 	 	(19,367	)	 	 	—	 	 	 	(24,912	)	 	 	 	 	
Accrued interest	 	 	33,985	 	 	 	40,488	 	 	 	128,761	 	 	 	—	 	 	 	203,234	 	 	 	 	 	
Other current liabilities	 	 	7,516	 	 	 	(8,560	)	 	 	48,736	 	 	 	—	 	 	 	47,692	 	 	 	 	 	
Other assets and liabilities	 	 	(4,428	)	 	 	10,818	 	 	 	4,333	 	 	 	—	 	 	 	10,723	 	 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	 	 	
Net Cash Provided (Used) by Operating Activities	 	 	399,458	 	 	 	818,439	 	 	 	(787,993	)	 	 	138	 	 	 	430,042	 	 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	 	 	
Cash Flows from Investing Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Acquisitions, net of liabilities assumed	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	 	
Proceeds from sale of discontinued operations	 	 	—	 	 	 	160,791	 	 	 	—	 	 	 	—	 	 	 	160,791	 	 	 	 	 	
Proceeds from sale of investments	 	 	—	 	 	 	68,517	 	 	 	—	 	 	 	—	 	 	 	68,517	 	 	 	 	 	
Proceeds from sale of turbines	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	 	
(Increase) in trust funds	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	 	
Decrease/(increase) in restricted cash	 	 	(138,798	)	 	 	(109,004	)	 	 	50,000	 	 	 	—	 	 	 	(197,802	)	 	 	 	 	
Decrease/(increase) in notes receivable	 	 	(28,247	)	 	 	(230,733	)	 	 	(29,728	)	 	 	79,464	 	 	 	(209,244	)	 	 	 	 	
Capital expenditures	 	 	(92,003	)	 	 	(1,349,163	)	 	 	1,433	 	 	 	—	 	 	 	(1,439,733	)	 	 	 	 	
Investments in projects	 	 	(36,047	)	 	 	(25,896	)	 	 	(2,053	)	 	 	—	 	 	 	(63,996	)	 	 	 	 	
Investment in subsidiaries	 	 	(27,967	)	 	 	—	 	 	 	(145,732	)	 	 	173,699	 	 	 	—	 	 	 	 	 	
Distributions from subsidiaries	 	 	—	 	 	 	—	 	 	 	216,751	 	 	 	(216,751	)	 	 	—	 	 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	 	 	
Net Cash Provided (Used) by Investing Activities	 	 	(323,062	)	 	 	(1,485,488	)	 	 	90,671	 	 	 	36,412	 	 	 	(1,681,467	)	 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	 	 	
136

Table of Contents
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	NRG Energy,	 	 	 	 	 	 	 	 	
 	 	Guarantor	 	Non- Guarantor	 	Inc.	 	Eliminations	 	Consolidated	 	 	 	 	
 	 	Subsidiaries

	 	Subsidiaries

	 	(Note Issuer)

	 	(1)

	 	Balance

	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	(In thousands)	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flows from Financing Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net borrowings under line of credit agreement	 	 	(40,000	)	 	 	—	 	 	 	830,000	 	 	 	—	 	 	 	790,000	 	 	 	 	 	
Proceeds from issuance of stock	 	 	—	 	 	 	—	 	 	 	4,065	 	 	 	—	 	 	 	4,065	 	 	 	 	 	
Proceeds from issuance of corporate units (warrants)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	 	
Proceeds from issuance of short term debt	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	 	
Capital contributions from parent	 	 	81,427	 	 	 	92,487	 	 	 	500,000	 	 	 	(173,914	)	 	 	500,000	 	 	 	 	 	
Distributions to parent	 	 	—	 	 	 	(216,751	)	 	 	—	 	 	 	216,751	 	 	 	—	 	 	 	 	 	
Proceeds from issuance of long-term debt	 	 	37,869	 	 	 	963,000	 	 	 	165,288	 	 	 	(79,387	)	 	 	1,086,770	 	 	 	 	 	
Principal payments on long-term debt	 	 	(99,331	)	 	 	(92,174	)	 	 	(740,000	)	 	 	—	 	 	 	(931,505	)	 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	 	 	
Net Cash Provided (Used) by Financing Activities	 	 	(20,035	)	 	 	746,562	 	 	 	759,353	 	 	 	(36,550	)	 	 	1,449,330	 	 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	 	 	
Effect of Exchange Rate Changes on Cash and Cash Equivalents	 	 	(1,092	)	 	 	20,426	 	 	 	5,616	 	 	 	—	 	 	 	24,950	 	 	 	 	 	
Change in Cash from Discontinued Operations	 	 	—	 	 	 	51,267	 	 	 	—	 	 	 	—	 	 	 	51,267	 	 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	 	 	
Net Increase in Cash and Cash Equivalents	 	 	55,269	 	 	 	151,206	 	 	 	67,647	 	 	 	—	 	 	 	274,122	 	 	 	 	 	
Cash and Cash Equivalents at Beginning of Period	 	 	8,134	 	 	 	76,929	 	 	 	1,675	 	 	 	—	 	 	 	86,738	 	 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	 	 	
Cash and Cash Equivalents at End of Period	 	$	63,403	 	 	$	228,135	 	 	$	69,322	 	 	$	—	 	 	$	360,860	 	 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

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

137

Table of Contents

NRG Energy, Inc. and Subsidiaries
Consolidating Statements of Operations
For the Year Ended December 31, 2001
Predecessor Company
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantor	 	Non- Guarantor	 	NRG Energy, Inc.	 	Eliminations	 	Consolidated	
 	 	Subsidiaries

	 	Subsidiaries

	 	(Note Issuer)

	 	(1)

	 	Balance

	
 	 	 	 	 	 	 	 	 	 	(In thousands)	 	 	 	 	 	 	 	 	
Operating Revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues from majority-owned operations	 	$	1,639,653	 	 	$	416,205	 	 	$	39,525	 	 	$	(9,786	)	 	$	2,085,597	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cost of majority-owned operations	 	 	1,066,404	 	 	 	320,448	 	 	 	125	 	 	 	(9,884	)	 	 	1,377,093	 	
Depreciation and amortization	 	 	103,192	 	 	 	33,315	 	 	 	5,576	 	 	 	—	 	 	 	142,083	 	
General, administrative and development	 	 	44,199	 	 	 	33,236	 	 	 	109,769	 	 	 	98	 	 	 	187,302	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total operating costs and expenses	 	 	1,213,795	 	 	 	386,999	 	 	 	115,470	 	 	 	(9,786	)	 	 	1,706,478	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Operating Income/(Loss)	 	 	425,858	 	 	 	29,206	 	 	 	(75,945	)	 	 	—	 	 	 	379,119	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Other Income (Expense)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Minority interest in (earnings)/losses of consolidated subsidiaries	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Equity earnings in consolidated subsidiaries	 	 	100,330	 	 	 	(323	)	 	 	409,872	 	 	 	(509,879	)	 	 	—	 	
Equity in earnings of unconsolidated affiliates	 	 	143,141	 	 	 	68,117	 	 	 	(1,226	)	 	 	—	 	 	 	210,032	 	
Write downs and losses on sales of equity method investments	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Other income, net	 	 	16,718	 	 	 	5,753	 	 	 	3,349	 	 	 	(2,837	)	 	 	22,983	 	
Interest expense	 	 	(144,897	)	 	 	(20,622	)	 	 	(201,429	)	 	 	2,837	 	 	 	(364,111	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Total other income/(expense)	 	 	115,292	 	 	 	52,925	 	 	 	210,566	 	 	 	(509,879	)	 	 	(131,096	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Income/(Loss) From Continuing Operations Before Income Taxes	 	 	541,150	 	 	 	82,131	 	 	 	134,621	 	 	 	(509,879	)	 	 	248,023	 	
Income Tax Expense/(Benefit)	 	 	140,153	 	 	 	28,404	 	 	 	(130,583	)	 	 	—	 	 	 	37,974	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Income/(Loss) From Continuing Operations	 	 	400,997	 	 	 	53,727	 	 	 	265,204	 	 	 	(509,879	)	 	 	210,049	 	
Income/(Loss) on Discontinued Operations, net of Income Taxes	 	 	307	 	 	 	54,848	 	 	 	—	 	 	 	—	 	 	 	55,155	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Net Income/(Loss)	 	$	401,304	 	 	$	108,575	 	 	$	265,204	 	 	$	(509,879	)	 	$	265,204	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

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

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NRG Energy, Inc. and Subsidiaries
Consolidating Statements of Cash Flows
For the Year Ended December 31, 2001
Predecessor Company
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	NRG Energy,	 	 	 	 	
 	 	Guarantor	 	Non-Guarantor	 	Inc.	 	Eliminations	 	Consolidated	
 	 	Subsidiaries

	 	Subsidiaries

	 	(Note Issuer)

	 	(1)

	 	Balance

	
 	 	 	 	 	 	 	 	 	 	(In thousands)	 	 	 	 	 	 	 	 	
Cash Flows from Operating Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income/(loss)	 	$	401,304	 	 	$	108,575	 	 	$	265,204	 	 	$	(509,879	)	 	$	265,204	 	
Adjustments to reconcile net income/(loss) to net cash provided by operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Distributions in excess of (less than) equity earnings of unconsolidated affiliates	 	 	(100,199	)	 	 	(119,002	)	 	 	(271,447	)	 	 	371,646	 	 	 	(119,002	)	
Depreciation and amortization	 	 	106,995	 	 	 	99,922	 	 	 	5,576	 	 	 	—	 	 	 	212,493	 	
Amortization of deferred financing costs	 	 	1,571	 	 	 	2,140	 	 	 	6,957	 	 	 	—	 	 	 	10,668	 	
Deferred income taxes and investment tax credits	 	 	24,908	 	 	 	8,379	 	 	 	(57,717	)	 	 	69,986	 	 	 	45,556	 	
Current tax expense — non cash contribution from members	 	 	99,022	 	 	 	(12,221	)	 	 	—	 	 	 	(86,801	)	 	 	—	 	
Unrealized (gains)/losses on derivatives	 	 	31,711	 	 	 	(3,218	)	 	 	(41,750	)	 	 	—	 	 	 	(13,257	)	
Minority interest	 	 	—	 	 	 	6,564	 	 	 	—	 	 	 	—	 	 	 	6,564	 	
Amortization of out of market power contracts	 	 	(54,963	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(54,963	)	
Cash provided by (used in) changes in certain working capital items, net of effects from acquisitions and dispositions	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Accounts receivable, net	 	 	98,003	 	 	 	1,506	 	 	 	(9,986	)	 	 	—	 	 	 	89,523	 	
Inventory	 	 	(102,424	)	 	 	(6,146	)	 	 	(2,561	)	 	 	—	 	 	 	(111,131	)	
Prepayments and other current assets	 	 	(5,593	)	 	 	(29,040	)	 	 	(1,897	)	 	 	—	 	 	 	(36,530	)	
Accounts payable	 	 	3,086	 	 	 	(12,374	)	 	 	4,776	 	 	 	—	 	 	 	(4,512	)	
Accounts payable-affiliates	 	 	(119,294	)	 	 	(213,323	)	 	 	132,946	 	 	 	204,660	 	 	 	4,989	 	
Accrued income taxes	 	 	—	 	 	 	—	 	 	 	(91,947	)	 	 	16,815	 	 	 	(75,132	)	
Accrued property and sales taxes	 	 	5,128	 	 	 	(1,061	)	 	 	(13	)	 	 	—	 	 	 	4,054	 	
Accrued salaries, benefits, and related costs	 	 	7,388	 	 	 	3,598	 	 	 	4,799	 	 	 	—	 	 	 	15,785	 	
Accrued interest	 	 	1,276	 	 	 	6,299	 	 	 	28,062	 	 	 	—	 	 	 	35,637	 	
Other current liabilities	 	 	46,796	 	 	 	10,153	 	 	 	25,805	 	 	 	—	 	 	 	82,754	 	
Other assets and liabilities	 	 	(49,596	)	 	 	(25,093	)	 	 	(7,997	)	 	 	—	 	 	 	(82,686	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Net Cash Provided (Used) by Operating Activities	 	 	395,119	 	 	 	(174,342	)	 	 	(11,190	)	 	 	66,427	 	 	 	276,014	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Cash Flows from Investing Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Acquisitions, net of liabilities assumed	 	 	(649,538	)	 	 	—	 	 	 	(2,163,579	)	 	 	—	 	 	 	(2,813,117	)	
Proceeds from sale of investments	 	 	—	 	 	 	4,063	 	 	 	—	 	 	 	—	 	 	 	4,063	 	
Decrease/(increase) in restricted cash	 	 	(5,037	)	 	 	(44,670	)	 	 	(50,000	)	 	 	—	 	 	 	(99,707	)	
Decrease/(increase) in notes receivable	 	 	36,073	 	 	 	16,769	 	 	 	506	 	 	 	(8,257	)	 	 	45,091	 	
Capital expenditures	 	 	(124,175	)	 	 	(928,495	)	 	 	(269,460	)	 	 	—	 	 	 	(1,322,130	)	
Investments in projects	 	 	(124,850	)	 	 	34,412	 	 	 	6,947	 	 	 	(66,350	)	 	 	(149,841	)	
Investments in subsidiaries	 	 	(24,050	)	 	 	—	 	 	 	(626,436	)	 	 	650,486	 	 	 	—	 	
Distributions from subsidiaries	 	 	—	 	 	 	—	 	 	 	418,000	 	 	 	(418,000	)	 	 	—	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Net Cash Provided (Used) by Investing Activities	 	 	(891,577	)	 	 	(917,921	)	 	 	(2,684,022	)	 	 	157,879	 	 	 	(4,335,641	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Cash Flows from Financing Activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net borrowings under line of credit agreement	 	 	40,000	 	 	 	—	 	 	 	162,000	 	 	 	—	 	 	 	202,000	 	
Proceeds from issuance of stock	 	 	—	 	 	 	—	 	 	 	475,464	 	 	 	—	 	 	 	475,464	 	
Proceeds from issuance of corporate units (warrants)	 	 	—	 	 	 	—	 	 	 	4,080	 	 	 	—	 	 	 	4,080	 	
Proceeds from issuance of short term debt	 	 	—	 	 	 	22,156	 	 	 	600,000	 	 	 	—	 	 	 	622,156	 	
Capital contributions from parent	 	 	551,424	 	 	 	99,062	 	 	 	—	 	 	 	(650,486	)	 	 	—	 	
Distributions to parent	 	 	(418,000	)	 	 	—	 	 	 	—	 	 	 	418,000	 	 	 	—	 	
Proceeds from issuance of long-term debt	 	 	445,397	 	 	 	1,342,166	 	 	 	1,472,274	 	 	 	8,180	 	 	 	3,268,017	 	
Principal payments on long-term debt	 	 	(118,480	)	 	 	(279,736	)	 	 	(19,955	)	 	 	—	 	 	 	(418,171	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Net Cash Provided (Used) by Financing Activities	 	 	500,341	 	 	 	1,183,648	 	 	 	2,693,863	 	 	 	(224,306	)	 	 	4,153,546	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Effect of Exchange Rate Changes on Cash and Cash Equivalents	 	 	922	 	 	 	(3,977	)	 	 	—	 	 	 	—	 	 	 	(3,055	)	
Change in Cash from Discontinued Operations	 	 	—	 	 	 	(40,873	)	 	 	—	 	 	 	—	 	 	 	(40,873	)	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Net Increase (Decrease) in Cash and Cash Equivalents	 	 	4,805	 	 	 	46,535	 	 	 	(1,349	)	 	 	—	 	 	 	49,991	 	
Cash and Cash Equivalents at Beginning of Period	 	 	3,329	 	 	 	30,394	 	 	 	3,024	 	 	 	—	 	 	 	36,747	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	
Cash and Cash Equivalents at End of Period	 	$	8,134	 	 	$	76,929	 	 	$	1,675	 	 	$	—	 	 	$	86,738	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

 	 	 	 	

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

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Note 31—Subsequent Event

    On May 13, 2004 we completed the sale of our 63% interest in Hsin Yu to Asia Pacific Energy Development Co., Ltd or “APED,” which resulted in net cash proceeds of approximately $1.0 million and a net gain of approximately $10.0 million.

    LSP Energy—Batesville—In August, 2004 we completed the sale of our 100 percent interest in an 837 megawatt generating plant in Batesville, Mississippi to Complete Energy Partners, LLC. We realized cash proceeds of $27.6 million.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON
FINANCIAL STATEMENT SCHEDULES

To the Board of Directors
and Stockholders of NRG Energy, Inc.:

     Our audits of the consolidated financial statements referred to in our report dated March 10, 2004 , except as to Notes 6, 20, 30 and 31, which are as of October 29, 2004, appearing in this Annual Report on Form 10-K also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Annual Report on Form 10-K Amendment No. 2. In our opinion, this financial statement schedule for the period from December 6, 2003 to December 31, 2003 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP
Minneapolis, Minnesota
March 10, 2004, except as to Notes 6, 20, 30 and 31, which are as of October 29, 2004.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON
FINANCIAL STATEMENT SCHEDULES

To the Board of Directors
and Stockholders of NRG Energy, Inc.:

     Our audits of the consolidated financial statements referred to in our report dated March 10, 2004 , except as to Notes 6, 20, 30 and 31, which are as of October 29, 2004, appearing in this Annual Report on Form 10-K also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Annual Report on Form 10-K Amendment No. 2. In our opinion, this financial statement schedule for the period from January 1, 2003 to December 5, 2003 and for the two years ended December 31, 2002, present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP
Minneapolis, Minnesota
March 10, 2004, except as to Notes 6, 20, 30 and 31, which are as of October 29, 2004.

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NRG ENERGY, INC.

SCHEDULE II. VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2003, 2002 and 2001
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Column A

	 	Column B

	 	Column C

	 	Column D

	 	Column E

	
 	 	 	 	 	 	Additions

	 	 	 	 	 	 	
 	 	Balance at	 	Charged to	 	Charged to	 	 	 	 	 	Balance at	
 	 	Beginning	 	Costs and	 	Other	 	 	 	 	 	End of	
Description

	 	of Period

	 	Expenses

	 	Accounts

	 	Deductions

	 	Period

	
 	 	 	 	 	 	(In thousands)	 	 	 	 	
Allowance for doubtful accounts, deducted from accounts receivable in the balance sheet:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Predecessor Company	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Year ended December 31, 2001	 	$	21,199	 	 	$	—	 	 	$	—	 	 	$	(7,565	)	 	$	13,634	 	
Year ended December 31, 2002	 	 	13,634	 	 	 	4,529	 	 	 	—	 	 	 	—	 	 	 	18,163	 	
January 1 - December 5, 2003	 	 	18,163	 	 	 	15,576	 	 	 	—	 	 	 	(33,739	)	 	 	—	*	
Reorganized NRG	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
December 6 - December 31, 2003	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	

*	December 6, 2003 — Fresh Start Balance	

 	 	 	 	 	 	Additions

	 	 	 	 	 	 	
 	 	Balance at	 	Charged to	 	 	 	 	 	 	 	 	 	Balance at	
 	 	Beginning of	 	Costs and	 	Charged to	 	 	 	 	 	End of	
Description

	 	Period

	 	Expenses

	 	Other

	 	Deductions

	 	Period

	
 	 	 	 	 	 	(In thousands)	 	 	 	 	
Income tax valuation allowance, deducted from deferred tax assets in the balance sheet:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Predecessor Company	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Year ended December 31, 2001	 	$	50,057	 	 	$	21,389	 	 	$	—	 	 	$	—	 	 	$	71,446	 	
Year ended December 31, 2002	 	 	71,446	 	 	 	1,006,540	 	 	 	92,315	 	 	 	—	 	 	 	1,170,301	 	
January 1 - December 5, 2003	 	 	1,170,301	 	 	 	71,315	 	 	 	—	 	 	 	—	 	 	 	1,241,616	*	
Reorganized NRG	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
December 6 - December 31, 2003	 	$	1,241,616	 	 	$	(515	)	 	$	—	 	 	$	—	 	 	$	1,241,101	 	

*	December 6, 2003 — Fresh Start Balance	
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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	
 	 	(Principal Executive Officer)	
Date: November 2, 2004

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EXHIBIT INDEX
 	 	 	
3.1	 	Amended and Restated Certificate of Incorporation.(2)	
3.2	 	Amended and Restated By-Laws.(7)	
4.1	 	Indenture dated as of December 23, 2003 by and among NRG Energy, Inc., certain subsidiaries of NRG Energy, Inc. and Law Debenture Trust Company of New York, as Trustee, re: NRG Energy, Inc.’s 8% Second Priority Senior Secured Notes due 2013.(2)	
4.2	 	Purchase Agreement dated as of December 17, 2003 by and among NRG Energy, Inc., as Issuer, certain subsidiaries of NRG Energy, Inc., as guarantors, and Lehman Brothers, Inc., Credit Suisse First Boston LLC, Citigroup Global Markets Inc. and Deutsche Bank Securities, Inc., as Initial Purchasers, re: $1,250,000,000 8% Second Priority Senior Secured Notes due 2013.(2)	
4.3	 	Registration Rights Agreement dated as of December 23, 2003 by and among NRG Energy, Inc,.as Issuer, certain subsidiaries of NRG Energy, Inc., as Guarantors, and Lehman Brothers Inc., Credit Suisse First Boston LLC, Citigroup Global Markets Inc. and Deutsche Bank Securities, Inc., as Initial Purchasers.(2)	
4.4	 	Purchase Agreement dated as of January 21, 2003 by and among NRG Energy, as Issuer, certain subsidiaries of NRG Energy, Inc., as Guarantors, and Credit Suisse First Boston LLC and Lehman Brothers, Inc., as Initial Purchasers, re:	
 	 	$475,000,000 8% Second Priority Senior Secured Notes due 2013.(2)	
4.5	 	Registration Rights Agreement dated as of January 28, 2004 by and among NRG Energy, Inc., as Issuer, certain subsidiaries of NRG Energy, Inc., as Guarantors, and Credit Suisse First Boston LLC and Lehman Brothers, Inc., as Initial Purchasers.(2)	
4.6	 	$1,450,000,000 Credit Agreement dated as of December 23, 2003 among NRG Energy, Inc. NRG Power Marketing, Inc., the Lenders party thereto, and Credit Suisse First Boston, acting through its Cayman Islands Branch, and Lehman Brothers Inc., as joint lead book runners and joint lead arrangers, Credit Suisse First Boston, acting though its Cayman Islands Branch, as administrative agent, General Electric Capital Corporation, as revolver agent, and Lehman Commercial Paper Inc., as syndication agent.(2)	
4.7	 	Guarantee and Collateral Agreement made by NRG Energy, Inc., NRG Power Marketing, Inc. and certain of the subsidiaries of NRG Energy, Inc. in favor of Deutsche Bank Trust Company Americas, as Collateral Trustee, Credit Suisse First Boston, acting through its Cayman Islands Branch, as Administrative Agent, and Law Debenture Trust Company of New York, as Trustee.(2)	
4.8	 	Collateral Trust Agreement dated as of December 23, 2003 among NRG Energy, Inc., NRG Power Marketing, Inc., the Guarantors from time to time party hereto, Credit Suisse First Boston, acting through its Cayman Islands Branch, as Administrative Agent, Law Debenture Trust Company of New York, as Trustee, and Deutsche Bank Trust Company Americas, as Collateral Trustee.(2)	
4.9	 	Amended and Restated Common Agreement among XL Capital Assurance Inc., Goldman Sachs Mitsui Marine Derivative	

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 	 	Products, L.P., Law Debenture Trust Company of New York, as Trustee, The Bank of New York, as Collateral Agent, NRG Peaker Finance Company LLC and each Project Company Party thereto dated as of January 6, 2004, together with Annex A to the Common Agreement.(2)	
4.10	 	Amended and Restated Security Deposit Agreement among NRG Peaker Finance Company, LLC and each Project Company party thereto, and the Bank of New York, as Collateral Agent and Depositary Agent, dated as of January 6, 2004.(2)	
4.11	 	NRG Parent Agreement by NRG Energy, Inc. in favor of the Bank of New York, as Collateral Agent, dated as of January 6, 2004.(2)	
4.12	 	Indenture dated June 18, 2002, between NRG Peaker Finance Company LLC, as Issuer, Bayou Cove Peaking Power LLC, big Cajun I Peaking Power LLC, NRG Rockford LLC, NRG Rockford II LLC and Sterlington Power LLC, as Guarantors, XL Capital Assurance Inc., as Insurer, and Law Debenture Trust Company, as Successor Trustee to the Bank of New York.(3)	
10.1  	*	Employment Agreement dated November 10, 2003 between NRG Energy, Inc. and David Crane.(2)	
10.2  	 	Note Agreement, dated August 20, 1993, between NRG Energy, Inc., Energy Center, Inc. and each of the purchasers named therein.(4)	
10.3  	 	Master Shelf and Revolving Credit Agreement, dated August 20, 1993, between NRG Energy, Inc., Energy Center, Inc., The Prudential Insurance Registrants of America and each Prudential Affiliate, which becomes party thereto.(4)	
10.4  	 	Asset Sales Agreement, dated December 23, 1998, between NRG Energy, Inc., and Niagara Mohawk Power Corporation.(5)	
10.5  	 	Generating Plant and Gas Turbine Asset Purchase and Sale Agreement for the Arthur Kill generating plants and Astoria gas turbines, dated January 27, 1999, between NRG Energy and Consolidated Edison Company of New York, Inc.(5)	
10.6  	 	Amendment to the Asset Sales Agreement, dated June 11, 1999, between NRG Energy, Inc., and Niagara Mohawk Power Corporation.(5)	
10.7  	 	Third Amended Joint Plan of Reorganization of NRG Energy, Inc., NRG Power Marketing, Inc., NRG Capital LLC, NRG Finance Company I LLC, and NRGenerating Holdings (No. 23) B.V.(6)	
10.8  	 	First Amended Joint Plan of Reorganization of NRG Northeast Generating LLC (and certain of its subsidiaries), NRG South Central Generating (and certain of its subsidiaries) and Berrians I Gas Turbine Power LLC.(6)	
10.9  	*	Key Executive Retention, Restructuring Bonus and Severance Agreement between NRG Energy, Inc. and Scott J. Davido dated July 1, 2003.(2)	
10.10	*	Severance Agreement between NRG Energy, Inc. and Ershel Redd Jr. dated January 30, 2003.(3)	
10.11	*	Severance Agreement between NRG Energy and William Pieper dated March 1, 2003.(2)	
10.12	*	Severance Agreement between NRG Energy, Inc. and George Schaefer dated December 18, 2002.(3)	
10.13	*	Severance Agreement between NRG Energy and John P. Brewster dated July 23, 2003.(2)	
10.14	 	Registration Rights Agreement, dated December 5, 2003, among NRG Energy, Inc. and the holders of NRG Energy, Inc. common stock named therein.(1)	
21     	 	Subsidiaries of NRG Energy. Inc.(2)	
23.1  	 	Consent of PricewaterhouseCoopers LLP.(1)	
31.1  	 	Rule 13a-14(a)/15d-14(a) certification of David Crane.(1)	
31.2  	 	Rule 13a-14(a)/15d-14(a) certification of Robert Flexon.(1)	
31.3  	 	Rule 13a-14(a)/15d-14(a) certification of James Ingoldsby.(1)	
32     	 	Section 1350 Certification.(1)	
99.1  	 	Financial Statements of “West Coast Power.”(2)	
99.2  	 	Financial Statements of Louisiana Generating LLC for the year ended December 31, 2003.(1)	
99.3  	 	Financial Statements of NRG Northeast Generating LLC for the year ended December 31, 2003.(1)	
99.4  	 	Financial Statements of Indian River Power LLC for the year ended December 31, 2003.(1)	
99.5  	 	Financial Statements of NRG MidAtlantic Generating LLC for the year ended December 31, 2003.(1)	
99.6  	 	Financial Statements of NRG South Central Generating LLC for the year ended December 31, 2003.(1)	
99.7  	 	Financial Statements of NRG Eastern LLC for the year ended December 31, 2003.(1)	
99.8  	 	Financial Statements of Northeast Generation Holding LLC for the year ended December 31, 2003.(1)	
99.9  	 	Financial Statements of NRG International LLC for the year ended December 31, 2003.(1)	

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*	 	Exhibit relates to compensation arrangements.	 	 	
 	
(1)	 	Filed herewith.	 	 	
 	
(2)	 	Incorporated herein by reference to NRG Energy, Inc.’s annual report on Form 10-K filed on March 16, 2004.	 	 	
 	
(3)	 	Incorporated herein by reference to NRG Energy, Inc.’s annual report on Form 10-K filed on March 31, 2003.	 	 	
 	
(4)	 	Incorporated herein by reference to NRG Energy’s Registration Statement on Form S-1, as amended, Registration No. 333-33397.	 	 	
 	
(5)	 	Incorporated herein by reference to NRG Energy, Inc.’s quarterly report on Form 10-Q for the quarter ended June 30, 1999.	 	 	
 	
(6)	 	Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on November 19, 2003.	 	 	
 	
(7)	 	Incorporated herein by reference to NRG Energy, Inc.’s quarterly report on Form 10-Q for the quarter ended June 30, 2004.	 	 	

 

Exhibit 10.14

Execution Copy

REGISTRATION RIGHTS AGREEMENT

by and among

NRG ENERGY, INC.

and

THE HOLDERS NAMED HEREIN

Dated as of December 5, 2003

 

Table of Contents
 	 	 	 	 	 	 	
 	 	 	 	Page	
1.	 	Definitions	 	 	1	 	
2.	 	Securities Act Registration on Request	 	 	5	 	
 	 	(a) Initiating Request	 	 	5	 	
 	 	(b) Registration of Other Securities	 	 	7	 	
 	 	(c) Registration Statement Form	 	 	7	 	
 	 	(d) Effective Registration Statement	 	 	8	 	
 	 	(e) Selection of Underwriters	 	 	8	 	
 	 	(f) Priority in Requested Registration	 	 	9	 	
3.	 	Piggyback Registration	 	 	9	 	
4.	 	Expenses	 	 	10	 	
5.	 	Registration Procedures	 	 	10	 	
6.	 	Underwritten Offerings	 	 	15	 	
 	 	(a) Requested Underwritten Offerings	 	 	15	 	
 	 	(b) Piggyback Underwritten Offerings: Priority	 	 	15	 	
 	 	(c) Participation in Underwritten Registrations	 	 	17	 	
 	 	(d) Holdback Agreements	 	 	17	 	
7.	 	Preparation; Confidentiality	 	 	18	 	
8.	 	Postponements	 	 	20	 	
9.	 	Indemnification	 	 	21	 	
 	 	(a) Indemnification by the Company	 	 	21	 	
 	 	(b) Indemnification by the Offerors and Sellers	 	 	22	 	
 	 	(c) Notices of Losses, etc.	 	 	22	 	
 	 	(d) Contribution	 	 	23	 	
 	 	(e) Other Indemnification	 	 	23	 	
 	 	(f) Indemnification Payments	 	 	23	 	
10.	 	Permitted Securities	 	 	23	 	
11.	 	Adjustments Affecting Registrable Common Stock	 	 	24	 	
12.	 	Rule 144 and Rule 144A	 	 	24	 	
13.	 	Amendments and Waivers	 	 	24	 	
14.	 	Nominees for Beneficial Owners	 	 	24	 	
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 	 	 	 	Page	
15.	 	Assignment	 	 	24	 	
16.	 	Restrictions on Transfer	 	 	25	 	
17.	 	Notice of Transfer	 	 	25	 	
18.	 	Calculation of Percentage or Number of Shares of Registrable Common Stock	 	 	26	 	
19.	 	Termination of Registration Rights	 	 	26	 	
20.	 	Miscellaneous	 	 	26	 	
 	 	(a) Further Assurances	 	 	27	 	
 	 	(b) Headings	 	 	27	 	
 	 	(c) Conflicting Instructions	 	 	27	 	
 	 	(d) Remedies	 	 	27	 	
 	 	(e) Entire Agreement	 	 	27	 	
 	 	(f) Notices	 	 	27	 	
 	 	(g) Governing Law	 	 	28	 	
 	 	(h) Severability	 	 	28	 	
 	 	(i) Counterparts	 	 	28	 	
SCHEDULES:

SCHEDULE A – JOINDER AGREEMENT

SCHEDULE B – ELECTION FORM

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REGISTRATION RIGHTS AGREEMENT

     REGISTRATION RIGHTS AGREEMENT (this “Agreement”) dated as of December 5, 2003 and effective as of the Effective Date (as hereinafter defined), by and among NRG Energy, Inc., a Delaware corporation (the “Company”), and each Holder (as hereinafter defined) of Registrable Common Stock (as hereinafter defined) who is either (i) an Original Record Holder (as hereinafter defined), (ii) an Original Other Holder (as hereinafter defined) who elects in writing to become a party to this Agreement or (iii) any other Person (as hereinafter defined) who becomes a party pursuant to the terms of this Agreement by entering into a Joinder Agreement (as hereinafter defined).

     In consideration of the premises and the mutual agreements set forth herein, the parties hereto hereby agree as follows:

1. Definitions. Unless otherwise defined herein, capitalized terms used herein and in the recitals above shall have the following meanings:

     “10% Holder” means, as of any date of determination, any Holder which owns 10% or more of the Company’s Common Stock then outstanding.

     “Affiliate” of a Person means any Person that directly, or indirectly through one or more intermediaries, controls, or is controlled by, or is under common control with, such other Person. For purposes of this definition, “control” means the ability of one Person to direct the management and policies of another Person. For purposes of this Agreement, each of MattlinPatterson Global Opportunities Partners, L.P. and MattlinPatterson Global Opportunities Partners (Bermuda), L.P. shall be an Affiliate of the other. In addition, with respect to each of MattlinPatterson Global Opportunities Partners, L.P. and MattlinPatterson Global Opportunities Partners (Bermuda), L.P., the term “Affiliate” shall also include its general partner, investment manager, any entity with the same general partner or investment manager as MattlinPatterson Global Opportunities Partners, L.P or MattlinPatterson Global Opportunities Partners (Bermuda), L.P. (as the case may be), and any Person under the direct or indirect control of MattlinPatterson Global Partners LLC or MattlinPatterson Global Advisers LLC and the general partner(s) and investment manager(s) of any such Person, if any.

     “Bankruptcy Code” means Title 11 of the United States Code.

     “Business Day” means any day except a Saturday, Sunday or other day on which commercial banks in New York City or Minneapolis are authorized or required by law to be closed.

     “Commission” means the U.S. Securities and Exchange Commission.

     “Common Stock” means the shares of common stock, $.01 par value per share, of the Company, as adjusted to reflect any merger, consolidation, recapitalization, reclassification, split-up, stock dividend, rights offering or reverse stock split made, declared or effected with respect to the Common Stock.

     “Company Indemnitee” has the meaning set forth in Section 9(a) hereof.

 

     “Confidential Material” means all notices delivered by the Company under this Agreement, including, without limitation, notices delivered by the Company pursuant to Section 2 and/or Section 3 (each, an “Offering Notice”) and any and all other information, in any form or medium, written or oral, concerning or relating to the Company (whether prepared by the Company, its Representatives or otherwise, and irrespective of the form or means of communication and which prior to the delivery of an Offering Notice is labeled or otherwise identified as confidential) that is furnished to a Holder of Registrable Common Stock or its Representative (or to a Person who was a Holder who has not notified the Company that it is no longer a Holder pursuant to Section 17) by or on behalf of the Company, including without limitation all such oral and written information relating to financial statements, projections, evaluations, plans, programs, customers, suppliers, facilities, equipment and other assets, products, processes, marketing, research and development, trade secrets, know-how, patent applications that that have not been published, technology and other confidential information and intellectual property of the Company. During the period beginning on the date of delivery of an Offering Notice and ending on the date that the registration referred to therein either becomes effective or is abandoned, all information provided to the Holders of Registrable Common Stock, who elect to participate in the offering referred to therein, in connection with such offering shall be deemed to be Confidential Material, whether or not labeled or otherwise identified as Confidential Information. “Confidential Material” shall not include information that: (a) is or becomes available to the public generally, other than as a result of disclosure by the relevant Holder or one of the Representatives of such Holder in breach of the terms of this Agreement, or (b) becomes available to the relevant Holder from a source other than the Company or one of the Representatives of such Holder, including without limitation prior to the date hereof, provided that, the Holder reasonably believes that such source is not bound by a confidentiality agreement with or does not have a contractual, legal or fiduciary obligation of confidentiality to the Company or any other Person with respect to such information.

     “Effective Date” means the effective date of the Plan pursuant to the terms thereof.

     “Equity Transfer” has the meaning set forth in Section 6(d) hereof.

     “Exchange Act” means the Securities Exchange Act of 1934, as amended, and the rules and regulations thereunder, or any similar or successor statute.

     “Expenses” means all expenses incident to the Company’s performance of or compliance with its obligations under this Agreement, including, without limitation, all registration, filing, listing, stock exchange and NASD fees (including, without limitation, all fees and expenses of any “qualified independent underwriter” required by the rules of the NASD), all fees and expenses of complying with state securities or blue sky laws (including the reasonable fees, disbursements and other charges of counsel for the underwriters in connection with blue sky filings), all word processing, duplicating and printing expenses, messenger, telephone and delivery expenses, all rating agency fees, the fees, disbursements and other charges of counsel for the Company and of its independent public accountants, including the expenses incurred in connection with any special audits or comfort letters required by or incident to such performance and compliance, the fees and expenses incurred in connection with the listing of the securities to be registered on each securities exchange or national market system on which similar securities

2

 

issued by the Company are then listed, the reasonable fees and disbursements of one law firm (per registration statement prepared) representing the Selling Holders (selected by the Selling Holders holding a majority of the shares of Registrable Common Stock covered by such registration), the fees and expenses of any special experts retained by the Company in connection with such registration, and the fees and expenses of other Persons retained by the Company, but excluding underwriting discounts and commissions and applicable transfer taxes, if any, which discounts, commissions and transfer taxes shall be borne by the Selling Holders in all cases; provided that, in any case where Expenses are not to be borne by the Company, such Expenses shall not include salaries of Company personnel or general overhead expenses of the Company, auditing fees, premiums or other expenses relating to liability insurance required by underwriters or other expenses for the preparation of financial statements or other data normally prepared by the Company in the ordinary course of its business or which the Company would have incurred in any event.

     “Holdback Period” has the meaning set forth in Section 6(d) hereof.

     “Holder” means, as of any date of determination, (a) any Original Record Holder or Original Other Holder who owns at least 1% of the Company’s Common Stock on the date of determination, or (b) any Person who (i) acquired at least 1% of the Company’s Common Stock then outstanding from an Original Record Holder or Original Other Holder, (ii) owns at least 10% of the Company’s Common Stock then outstanding and (iii) has delivered to the Company a Joinder Agreement in accordance with Section 15.

     “Holder Indemnitee” has the meaning set forth in Section 9(b) hereof.

     “Initiating Holder” means at the time of any Initiating Request a 10% Holder.

     “Initiating Holder Group” means Holders (not including any 10% Holder) which collectively own 10% or more of the Company’s Common Stock outstanding at the time of delivery of an Initiating Request.

     “Initiating Request” has the meaning set forth in Section 2(a) hereof.

     “Joinder Agreement” has the meaning set forth in Section 15 hereof.

     “Loss” and “Losses” have the meanings set forth in Section 9(a) hereof.

     “Material Adverse Change” means (a) any general suspension of trading in securities on any national securities exchange or in the over-the-counter market in the United States of America; (b) the declaration of a banking moratorium or any suspension of payments in respect of banks in the United States of America; (c) the commencement of war, armed hostilities, terrorism or other national or international calamity involving the United States of America; (d) any other limitation (whether or not voluntary) imposed by any governmental authority of the United States of America, which materially affects the extension of credit by U.S. banks or other financial institutions; (e) any material adverse change in the business, condition (financial or otherwise) or prospects of the Company and its subsidiaries, taken as a whole (provided that, if the registration is with respect to an underwritten offering, in no event shall any such change be deemed to be a Material Adverse Change if the offering price remains

3

 

within the range originally advised by the underwriter); or (f) a 20% or more decline in the Dow Jones Industrial Average, the Standard and Poor’s Index of 500 Industrial Companies or the Dow Jones Utilities Index, in each case from the date of an Initiating Request.

     “NASD” means the National Association of Securities Dealers, Inc.

     “Non-withdrawing Holders” has the meaning set forth in Section 2(a)(ii)(D) hereof.

     “Offering Documents” has the meaning set forth in Section 9(a) hereof.

     “Original Other Holder” means any Person (other than Cede & Co. and the escrow agent for the Disputed Claims Reserve (as defined in the Plan)) who (a) shall own beneficially and/or of record, in each case together with such Person’s Affiliates, at least 1,000,000 shares of the Common Stock as of the Effective Date (immediately after giving effect to the initial issuance of shares of Common Stock pursuant to the Plan and assuming for this purpose that such shares were initially issued on the Effective Date), (b) delivers written notice to the Company in the form of Schedule B attached hereto, signed by such Person and each of its Affiliates (if any), and elects in such notice to become a party to this Agreement and (c) continues to own at least 1,000,000 shares of Common Stock as of the date of such notice.

     “Original Record Holder” means any Person (other than Cede & Co. and the escrow agent for the Disputed Claims Reserve (as defined in the Plan)) who shall own of record (excluding any ownership by such Person’s Affiliates) at least 1,000,000 shares of Common Stock as of the Effective Date (immediately after giving effect to the initial issuance of shares of Common Stock pursuant to the Plan and assuming for this purpose that such shares were initially issued on the Effective Date).

     “Permitted Securities” has the meaning set forth in Section 2(b) hereof.

     “Person” means any individual, corporation, partnership, limited liability company, firm, joint venture, association, joint stock company, trust, unincorporated organization, governmental or regulatory body or subdivision thereof or other entity.

     “Piggyback Registration” has the meaning set forth in Section 3 hereof.

     “Piggyback Requesting Holder” has the meaning set forth in Section 3 hereof.

     “Plan” means the Plan of Reorganization under Chapter 11 of the Bankruptcy Code for the Company and certain of its domestic subsidiaries, as the same may be amended, modified or supplemented from time to time in accordance with the terms thereof.

     “Public Offering” means a public offering and sale of Common Stock pursuant to an effective registration statement (other than a registration statement on Form S-4 or Form S-8 or any successor or similar forms) under the Securities Act.

     “Registrable Common Stock” means any of the Common Stock owned by the Holders from time to time; provided, however, that a share of Common Stock will cease to be

4

 

Registrable Common Stock when (a) a registration statement covering such Registrable Common Stock has been declared effective and such Registrable Common Stock has been sold pursuant to such effective registration statement, or (b) such Registrable Common Stock has been Transferred to a Person who is not (and does not become as a result of such Transfer) a Holder.

     “Representative” has the meaning set forth in Section 7(b) hereof.

     “Securities Act” means the Securities Act of 1933, as amended, and the rules and regulations thereunder, or any similar or successor statute.

     “Selling Holder” means a Holder who is selling Registrable Common Stock requested to be registered pursuant to Section 2(a) or Section 3 hereof.

     “Transfer” means any transfer, sale, assignment, pledge, hypothecation or other disposition of any interest. “Transferor” and “Transferee” have correlative meanings.

     “Withdrawal Notice” has the meaning set forth in Section 19 hereof.

     In this Agreement, all references to “ownership” of Common Stock or Registrable Common Stock shall be deemed to mean the beneficial ownership of Common Stock or Registrable Common Stock, unless otherwise specified.
2.	 	Securities Act Registration on Request.	
     (a) Initiating Request. At any time and from time to time after the first anniversary following the Effective Date and if the Company’s obligations hereunder have not terminated pursuant to and in accordance with the terms of Section 19 hereof, any Initiating Holder or Initiating Holder Group may make a written request (the “Initiating Request”) for the registration with the Commission under the Securities Act of all or part of the Registrable Common Stock owned by such Initiating Holder or Initiating Holder Group; provided, however, such request shall specify the number of shares to be disposed of by such Initiating Holder or Initiating Holder Group and the proposed plan of distribution therefor. Upon the receipt of any Initiating Request for registration pursuant to this Section 2(a), the Company shall promptly (and in any event within 10 Business Days after receipt of the Initiating Request) notify in writing all other Holders of the receipt of such request and will use its reasonable best efforts to effect, at the earliest practicable date, such registration under the Securities Act of:
 	(i)	 	the Registrable Common Stock which the Company has been so requested to register by such Initiating Holder or Initiating Holder Group, and	 	
 	
 	(ii)	 	all other Registrable Common Stock which the Company has been requested to register by any other Holders by written request (provided that, if such Holder shall specify in such request that it does not wish to receive any Confidential Material, except as set forth in such request, then the Company shall not deliver to such Holder any such Confidential Material) given to the Company within 30 days after the giving of written notice by the Company to such other Holders of the Initiating Request,	 	
5

 
all to the extent necessary to permit the disposition (in accordance with Section 2(c) hereof) of the Registrable Common Stock so to be registered; provided that,
 	(A)	 	(i) any Initiating Holder shall be permitted to make an Initiating Request on up to two occasions and (ii) any Initiating Holder Group shall be permitted to make an Initiating Request on one occasion only; provided, however, that if at any time there ceases to be a 10% Holder and at least one of the two written requests provided for in clause (i) of this paragraph (A) has not been used, any Initiating Holder Group shall have the right to make an additional Initiating Request and the number of Initiating Requests referenced in clause (i) of this paragraph (A) shall be permanently reduced to one; provided further that, the Company shall not be required to effect more than a total of three registrations pursuant to this Section 2(a) for all Holders;	 	
 	
 	(B)	 	the Company shall not be required to effect such registration pursuant to this Section 2(a) unless the disposition of the Registrable Common Stock shall be conducted through an underwritten offering on a “firm commitment” basis, unless the Initiating Request is made by (i) an Initiating Holder who is a 10% Holder, or (ii) an Initiating Holder Group, a member of which was but is no longer a 10% Holder but is an “affiliate” of the Company for purposes of Rule 144 under the Securities Act;	 	
 	
 	(C)	 	if the Company shall have previously effected a registration pursuant to this Section 2(a) or shall have previously effected a registration of which notice has been given to the Holders pursuant to Section 3 hereof, the Company shall not be required to effect any registration pursuant to this Section 2(a) until a period of 180 days shall have elapsed from the date on which the previous such registration ceased to be effective;	 	
 	
 	(D)	 	any Initiating Holder or Initiating Holder Group (at the request of those members of such Initiating Holder Group owning a majority of the shares of Registrable Common Stock owned by all members of such Initiating Holder Group) whose Registrable Common Stock was to be included in any registration pursuant to this Section 2(a), by written notice to the Company, may withdraw its Initiating Request. Upon receipt of such withdrawal notice (except as otherwise provided in sub-clause (x)), the Company shall not effect such registration and such registration shall not count as one of the permitted registrations pursuant to paragraph (A) above; provided that (x) if the members of an Initiating Holder Group that have not requested withdrawal of an Initiating Request collectively own and wish the Company to register the offering of 10% or more of the Company’s Common Stock outstanding at the time of	 	
6

 

 	 	 	delivery of the Initiating Request (the “Non-withdrawing Holders”), the Company shall effect a registration that includes only such shares of Common Stock owned by the Non-withdrawing Holders and such registration shall count as one of the registrations permitted for an Initiating Holder Group pursuant to paragraph (A) above; (y) any Initiating Holder may withdraw its Initiating Request not more than twice and any Initiating Holder Group may withdraw its Initiating Request not more than twice (provided further for the avoidance of doubt that the aggregate number of withdrawals under this clause (y) by all Initiating Holder Groups however constituted shall not exceed two), in either case unless such Initiating Request is withdrawn for a reason specified in sub-clause (z)(i); and (z) the Initiating Holder or Initiating Holder Group shall either (i) elect to pay or reimburse the Company for all Expenses incurred in connection with the second registration that is not effected as the result of an Initiating Request that is withdrawn by such Initiating Holder or Initiating Holder Group, as the case may be, pursuant to this paragraph (D), unless such Initiating Request is withdrawn either (I) at the request of the Company, (II) because a breach by the Company of its obligations under this Agreement has materially and adversely affected the offering, or (III) within 5 Business Days following the occurrence of a Material Adverse Change, in which case the Company shall pay all Expenses incurred in connection with such registration, or (ii) have the withdrawn Initiating Request count as one of the permitted registrations pursuant to paragraph (A) above; and	 	
 	
 	(E)	 	the Company shall not be required to effect any registration to be effected pursuant to this Section 2(a) unless at least 10% of the shares of Registrable Common Stock outstanding at the time of such request is to be included in such registration.	 	
     (b) Registration of Other Securities. Whenever the Company shall effect a registration pursuant to Section 2(a) hereof, no securities other than (i) Registrable Common Stock, (ii) subject to Section 2(f), Common Stock to be sold by the Company for its own account, and (iii) Common Stock or other capital stock issued in connection with equity investments in the Company or its subsidiaries or acquisitions (such Common Stock or other capital stock, which shall not include Common Stock outstanding on the Effective Date, is referred to as “Permitted Securities”) for which the Company’s board of directors has approved of the granting of such registration rights shall be included among the securities covered by such registration, unless otherwise approved by the Holders owning a majority of the shares of Registrable Common Stock covered by such registration, which approval shall not be unreasonably withheld.

     (c) Registration Statement Form. Registrations under Section 2(a) hereof shall be on such appropriate registration form prescribed by the Commission under the Securities Act as

7

 

shall be selected by the Company and which form shall be available for the sale of the Registrable Common Stock to be registered thereunder in accordance with the intended method of distribution thereof. The Company agrees to include in any such registration statement filed pursuant to Section 2(a) hereof all information which counsel for the Selling Holders holding a majority of the shares of Registrable Common Stock covered by such registration effected pursuant hereto shall advise is legally required to be included. The Company may, if permitted by law, effect any registration requested under this Section 2 by the filing of a registration statement on Form S-3 (or any successor or similar short form registration statement); provided, however, that in the case of an underwritten offering, if the managing underwriters advise the Company that in their opinion the use of another permitted form is of material importance to the success of the offering, then the Company shall effect such registration on such other permitted form.

     (d) Effective Registration Statement. Except as set forth in Section 2(a)(ii)(D), a registration requested pursuant to Section 2(a) hereof shall not be deemed to have been effected:
 	(i)	 	unless a registration statement with respect thereto has been declared effective by the Commission and remains effective in compliance with the provisions of the Securities Act and the laws of any state or other jurisdiction applicable to the disposition of Registrable Common Stock covered by such registration statement until the earlier of (x) such time as all of such Registrable Common Stock has been disposed of in accordance with such registration statement, (y) there shall cease to be any Registrable Common Stock or (z) 120 days after such registration statement is declared effective;	 	
 	
 	(ii)	 	if, after it has become effective, such registration is interfered with by any stop order, injunction or other order or requirement of the Commission or other governmental or regulatory agency or court for any reason other than a violation of applicable law solely by any Selling Holder and has not thereafter become effective; or	 	
 	
 	(iii)	 	if, in the case of an underwritten offering, the conditions to closing specified in an underwriting agreement to which the Company is a party are not satisfied or waived other than solely by reason of any breach or failure by any Selling Holder, or are not otherwise waived.	 	
      The Holders to be included in a registration statement may at any time terminate a request for registration made pursuant to Section 2(a) in accordance with Section 2(a)(ii)(D).

     (e) Selection of Underwriters. The underwriter or underwriters of each underwritten offering of the Registrable Common Stock to be registered pursuant to Section 2(a) hereof shall be selected by the Company (provided that, the managing underwriter must be a “bulge bracket” investment banking firm), subject to (i) if a 10% Holder or former 10% Holder is not the Initiating Holder or a member of the Initiating Holder Group, the approval of the Selling Holders owning a majority of the shares of Registrable Common Stock to be registered which approval shall not be unreasonably withheld or delayed, or (ii) if a 10% Holder or former 10% Holder is

8

 

the Initiating Holder or a member of the Initiating Holder Group, the approval of such 10% Holder or such former 10% Holder which approval may be withheld in its sole discretion; provided, however, that in any event the Company shall be satisfied that the terms of such underwriting engagement are commercially reasonable market terms.

     (f) Priority in Requested Registration. If the managing underwriter of an underwritten offering pursuant to Section 2(a) shall advise the Company (in which case, the Company shall use reasonable efforts to advise the Selling Holders) that, in its judgment, the number and type of securities proposed to be included in such registration would exceed the number and type of securities which could be sold in such offering within a price range acceptable to the Company and the Selling Holders owning at least a majority of the shares of Registrable Common Stock covered by such registration, then the Company shall include in such registration pursuant to Section 2(a), to the extent of the number and type of securities which the Company is so advised can be sold in such offering, (i) first, Registrable Common Stock requested to be registered by the Selling Holders pursuant to Section 2(a) hereof, pro rata among the Selling Holders on the basis of the number of shares of Registrable Common Stock requested to be registered by all such Selling Holders, (ii) second, Permitted Securities requested to be registered by the holders of Permitted Securities, pro rata among the holders of Permitted Securities on the basis of the number of Permitted Securities requested to be registered by all such holders of Permitted Securities and (iii) third, securities that the Company proposes to issue and sell for its own account.

3. Piggyback Registration. If the Company proposes to file a registration statement under the Securities Act with respect to an equity offering by the Company (or any offering by the Company of securities convertible into or exchangeable for equity securities) for its own account or for the account of any of its respective securityholders of any class of equity security or security convertible into or exchangeable for equity securities (other than a registration statement on Form S-4 or S-8 (or any substitute form that may be adopted by the Commission) or a registration statement to be filed in connection with an exchange offer or offering of securities solely to the Company’s existing securityholders), then the Company shall give written notice (which notice shall include a range of expected public offering prices; provided, however, if the underwriter has not advised the Company of such a range as of the date of such notice, then the Company shall notify the Holders in writing as promptly as practicable after it receives such advice from such underwriter) of such proposed filing to the Holders as soon as reasonably practicable (and in any event at least 30 days prior to such proposed registration), and such notice shall offer such Holders the opportunity to register such number of shares of Registrable Common Stock as each such Holder may request in writing in accordance with the provisions of this Section 3 (a “Piggyback Registration”). Upon written request, any Holder receiving notice of such proposed registration (a “Piggyback Requesting Holder”) made within 30 days after the receipt of any such notice (10 days if the Company states in such written notice or gives telephonic notice to the relevant Holder, with written confirmation to follow promptly thereafter, stating that (a) such registration will be on Form S-3 (or any successor form) and (b) such shorter period of time is required because of a planned filing date), which request shall specify the number of shares of Registrable Common Stock intended to be disposed of by such Piggyback Requesting Holder (provided that, if such Holder shall specify in such request that it does not wish to receive any Confidential Material, except as set forth in such request, then the Company shall not deliver to such Holder any such Confidential Material), the Company shall, subject to

9

 

Section 6(b) hereof, be obligated to permit the Registrable Common Stock requested to be included in a Piggyback Registration to be included on the same terms and conditions as any similar securities of the Company included therein, unless (i) the managing underwriter of an underwritten offering pursuant to this Section 3 has determined that the inclusion of such Registrable Common Stock would have a material adverse effect on the offering, and (ii) the Holders of a majority of the shares of Registrable Common Stock approve of such exclusion; provided that, if at any time after giving written notice of its intention to register any securities and prior to the effective date of the registration statement filed in connection with such registration, the Company shall determine for any reason not to register or to delay registration of such securities, the Company shall give written notice of such determination to each Piggyback Requesting Holder and (i) in the case of a determination not to register, shall be relieved of its obligation to register any Registrable Common Stock in connection with such registration (but not from any obligation of the Company to pay the Expenses in connection therewith), without prejudice, however, to the rights of any Holder to include Registrable Common Stock in any future registration (or registrations) pursuant to this Section 3 or to cause such registration to be effected as a registration under Section 2(a) hereof, as the case may be, and (ii) in the case of a determination to delay registering, shall be permitted to delay in each case registering any Registrable Common Stock, for the same period as the delay in registering such other securities. Notwithstanding the foregoing, prior to the date on which the securities to be sold in such offering are priced, if the managing underwriter (if an underwritten offering) notifies the Company of a change in the price range at which it believes the securities will be sold from the price range the Company previously provided to such Piggyback Requesting Holders, the Company shall so advise the Piggyback Requesting Holders, and each Piggyback Requesting Holder shall then have the right irrevocably to withdraw its request to have its Registrable Common Stock included in such registration by delivery of written notice of such withdrawal to the Company within five Business Days after having received such notice from the Company, without prejudice, however, to the rights of any Holder to include Registrable Common Stock in any future registration (or registrations) pursuant to this Section 3 or to cause such registration to be effected as a registration under Section 2(a) hereof, as the case may be.

     No registration effected under this Section 3 shall relieve the Company of its obligation to effect any registration upon request under Section 2(a) hereof and no registration effected pursuant to this Section 3 shall be deemed to have been effected pursuant to Section 2(a) hereof.

4. Expenses. Except as otherwise provided in clause (z) of Section 2(a)(ii)(D) and the final paragraph of Section 5, the Company shall pay all Expenses in connection with any registration initiated pursuant to Sections 2(a) or 3 hereof, whether or not such registration shall become effective and whether or not all or any portion of the shares of Registrable Common Stock originally requested to be included in such registration are ultimately included in such registration.

5. Registration Procedures. If and whenever the Company is required or elects to effect any registration under the Securities Act as provided in Sections 2(a) and 3 hereof, the Company shall, as expeditiously as possible:

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 	(a)	 	prepare and file with the Commission (promptly and, in the case of any registration pursuant to Section 2(a), in any event on or before the date that is (i) 90 days after the end of the period within which requests may be given to the Company pursuant to Section 2(a)(ii), or (ii) if, as of such 90th day, the Company does not have the audited financial statements required to be included in the registration statement, 30 days after the receipt by the Company from its independent public accountants of such audited financial statements, which the Company shall use its reasonable best efforts to obtain as promptly as practicable) the requisite registration statement to effect such registration and thereafter use its reasonable best efforts to cause such registration statement to become and remain effective; provided, however, that the Company may discontinue any registration of its securities that are not shares of Registrable Common Stock (and, under the circumstances specified in Sections 3 and 8(b) hereof, its securities that are shares of Registrable Common Stock) at any time prior to the effective date of the registration statement relating thereto;	 	
 	
 	(b)	 	prepare and file with the Commission such amendments and supplements to such registration statement and the prospectus used in connection therewith as may be necessary to keep such registration statement effective and to comply with the provisions of the Securities Act and the Exchange Act with respect to the disposition of all Registrable Common Stock covered by such registration statement until such time as all of such Registrable Common Stock has been disposed of in accordance with the method of disposition set forth in such registration statement (subject to Section 5(a)); provided that, such period need not extend beyond 120 days after the effective date of the registration statement;	 	
 	
 	(c)	 	furnish to each Selling Holder and each underwriter such number of copies of such drafts and final conformed versions of such registration statement and of each such amendment and supplement thereto (in each case including all exhibits and any documents incorporated by reference), such number of copies of such drafts and final versions of the prospectus contained in such registration statement (including each preliminary prospectus and any summary prospectus), if any, and any other prospectus filed under Rule 424 under the Securities Act, in conformity with the requirements of the Securities Act, and such other documents, as the Selling Holders and underwriters may reasonably request in writing;	 	
 	
 	(d)	 	use its reasonable best efforts (i) to register or qualify all Registrable Common Stock and other securities, if any, covered by such registration statement under such other securities or blue sky laws of such states or other jurisdictions of the United States of America as the Selling Holders shall reasonably request in writing, (ii) to keep such registration or qualification in effect for so long as such registration statement remains in effect and (iii) to take any other action that may be necessary or reasonably advisable to enable such Selling Holders to consummate the disposition in such jurisdictions of the securities to be sold by such Selling Holders, except that the Company shall not for any such purpose be required to qualify generally to do business as a foreign corporation in any jurisdiction wherein it would not but for the requirements of this Section 5(d) be	 	
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 	 	 	obligated to be so qualified, to subject itself to taxation in such jurisdiction or to consent to general service of process in any such jurisdiction;	 	
 	
 	(e)	 	use its reasonable best efforts to cause all Registrable Common Stock and other securities, if any, covered by such registration statement to be registered with or approved by such other federal or state governmental agencies or authorities as may be necessary in the opinion of counsel to the Company and counsel to the Selling Holder or Selling Holders to enable the Selling Holder or Selling Holders thereof to consummate the disposition of such Registrable Common Stock;	 	
 	
 	(f)	 	use its reasonable best efforts to obtain and, if obtained, furnish to each Selling Holder, and each underwriter a signed copy, addressed to each such underwriter, of:	 	
 	
 	 	 	     (i) an opinion or opinions of counsel to the Company dated the effective date of such registration statement (and, if such registration involves an underwritten offering, dated the date of the closing under the underwriting agreement), and	 	
 	
 	 	 	     (ii) a comfort letter or comfort letters, dated the effective date of such registration statement (and, if such registration involves an underwritten offering, dated the date of the closing under the underwriting agreement), from the independent public accountants who have certified the Company’s financial statements included or incorporated by reference in such registration statement,	 	
 	
 	 	 	     each in customary form, covering such matters of the type customarily covered by opinions of counsel or comfort letters, as the case may be, and reasonably satisfactory to the managing underwriter;	 	

 	(g)	 	notify each Selling Holder and the managing underwriter or underwriters, if any, promptly, and confirm such advice promptly in writing thereafter (i) when the registration statement, the prospectus or any prospectus supplement related thereto or post-effective amendment to the registration statement has been filed and, with respect to the registration statement and any post-effective amendment, when the same has become effective; (ii) of any request by the Commission for amendments or supplements to the registration statement or prospectus or for additional information; (iii) of the issuance by the Commission of any stop order suspending the effectiveness of the registration statement or the initiation of any proceedings by any Person for that purpose; (iv) if at any time the representations and warranties of the Company made as contemplated by Section 6(a) ceases to be true and correct; and (v) of the receipt by the Company of any notification with respect to the suspension of the qualification of any Registrable Common Stock for sale under the securities or blue sky laws of any jurisdiction or the initiation or threat of any proceeding for such purpose;	 	
 	
 	(h)	 	promptly notify each Selling Holder and the managing underwriter or underwriters, if any, at any time when a prospectus relating thereto is required to	 	
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 	 	 	be delivered under the Securities Act, upon discovery that, or upon the happening of any event as a result of which, the prospectus included in such registration statement, as then in effect, includes an untrue statement of a material fact or omits to state any material fact required to be stated therein or necessary to make the statements therein not misleading in the light of the circumstances under which they were made and, at the written request of any such Selling Holder or underwriter, if any, promptly prepare and furnish to it a reasonable number of copies of a supplement to or an amendment of such prospectus as may be necessary so that, as thereafter delivered to the purchasers of such securities, such prospectus, as supplemented or amended, shall not include an untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary to make the statements therein not misleading in the light of the circumstances under which they were made; provided that, in the event the Company shall give such notice, the Company shall extend the period for which such registration shall remain effective by the number of days during the period of days from and including the date of the giving of such notice to the date when the Company shall make available to the Holders such supplemented and amended prospectus;	 	
 	
 	(i)	 	use its reasonable best efforts to obtain the withdrawal of any order suspending the effectiveness of a registration statement relating to the Registrable Common Stock at the earliest possible moment;	 	
 	
 	(j)	 	otherwise comply with all applicable rules and regulations of the Commission and any other governmental agency or authority having jurisdiction over the offering, and make available to its security holders, as soon as reasonably practicable, an earnings statement covering the period of at least twelve months, which earnings statement shall satisfy the provisions of Section 11(a) of the Securities Act and Rule 158 promulgated thereunder, furnish to each Selling Holder and to the managing underwriter at least 10 days prior to the filing thereof a copy of any amendment or supplement to such registration statement or prospectus, and not file any amendment or supplement thereof which does not comply in all material respects with the requirements of the Securities Act or the rules and regulations thereunder;	 	
 	
 	(k)	 	use its reasonable best efforts to cause all such Registrable Common Stock covered by a registration statement to be listed or quoted on each securities exchange or inter-dealer automated quotation system on which similar securities issued by the Company are then listed or quoted;	 	
 	
 	(l)	 	provide and maintain a transfer agent and registrar for the Registrable Common Stock covered by a registration statement from and after a date no later than the effective date thereof;	 	
 	
 	(m)	 	enter into such agreements (including, in the case of an underwritten offering, an underwriting agreement in customary form) and take such other actions as the Selling Holders holding a majority of the shares of Registrable Common Stock	 	
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 	 	 	covered by such registration statement shall reasonably request in order to expedite or facilitate the disposition of such Registrable Common Stock, including customary indemnification;	 	
 	
 	(n)	 	if requested by the managing underwriter or the Selling Holders holding a majority of the shares of Registrable Common Stock being sold, promptly incorporate in a prospectus supplement or post-effective amendment such information as the managing underwriter or the Selling Holders of a majority of the Registrable Common Stock being sold, as the case may be, agree should be included therein relating to the plan of distribution with respect to such Registrable Common Stock, including without limitation, information with respect to the number of shares of Registrable Common Stock being sold to such underwriters, the purchase price being paid therefor by such underwriters and with respect to any other terms of the underwritten offering of the Registrable Common Stock to be sold in such offering; and make all required filings of such prospectus supplement or post-effective amendment as soon as notified of the matters to be incorporated in such prospectus supplement or post-effective amendment;	 	
 	
 	(o)	 	if requested by the Selling Holders holding a majority of the shares of Registrable Common Stock being sold, cooperate with the such Selling Holders and the managing underwriter, if any, to facilitate the timely preparation and delivery of certificates representing Registrable Common Stock to be sold and not bearing any restrictive legends, and enable such Registrable Common Stock to be in such share amounts and registered in such names as the managing underwriter or, if none, the Selling Holders holding a majority of the shares of Registrable Common Stock being sold, may request at least three Business Days prior to any sale of Registrable Common Stock to the underwriters; and	 	
 	
 	(p)	 	cause representatives of the Company to participate in any “road show” or “road shows” reasonably requested by any lead underwriter of an underwritten offering of Registrable Common Stock.	 	
        As a condition to the obligations of the Company to complete any registration pursuant to this Agreement with respect to the Registrable Common Stock of a Selling Holder, such Selling Holder must furnish to the Company in writing such information regarding itself and the Registrable Common Stock held by it as is necessary to effect the registration of such Selling Holder’s Registrable Common Stock and is requested in writing by the Company. At least 30 days prior to the first anticipated filing date of a registration statement for any registration under this Agreement, the Company will notify in writing each Holder of the information referred to in the preceding sentence which the Company is requesting from that Holder whether or not such Holder has elected to have any of its Registrable Common Stock included in the registration statement. If, within 10 days prior to the anticipated filing date, the Company has not received the requested information from a Holder, then the Company may file the registration statement without including Registrable Common Stock of that Holder.

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        Each Selling Holder agrees that as of the date that a final prospectus is made available to it for distribution to prospective purchasers of its Registrable Common Stock it shall cease to distribute copies of any preliminary prospectus prepared in connection with the offer and sale of such Registrable Common Stock. Each Selling Holder further agrees that, upon receipt of any notice from the Company of the happening of any event of the kind described in Section 5(h), such Selling Holder shall forthwith discontinue such Selling Holder’s disposition of Registrable Common Stock pursuant to the registration statement relating to such Registrable Common Stock until such Selling Holder’s receipt of the copies of the supplemented or amended prospectus contemplated by Section 5(h) and, if so directed by the Company, shall deliver to the Company (at the Company’s expense) all copies, other than permanent file copies, then in such Selling Holder’s possession of the prospectus relating to such Registrable Common Stock current at the time of receipt of such notice. If any event of the kind described in Section 5(h) occurs and such event is the fault solely of a Selling Holder (or Selling Holders), such Selling Holder (or such Selling Holders) shall pay all Expenses attributable to the preparation, filing and delivery of any supplemented or amended prospectus contemplated by Section 5(h).
6.	 	Underwritten Offerings.	
     (a) Requested Underwritten Offerings. If requested by the underwriters in connection with a request for a registration under Section 2(a) hereof, the Company shall enter into a firm commitment underwriting agreement with such underwriters for such offering, such agreement to be reasonably satisfactory in substance and form to the Company and the Selling Holders holding a majority of the shares of Registrable Common Stock included in such registration, and the underwriters and to contain such representations and warranties by the Company and such other terms as are customary in agreements of that type, including, without limitation, indemnification and contribution to the effect and to the extent provided in Section 9 hereof.

     (b) Piggyback Underwritten Offerings: Priority.
 	(i)	 	If the Company proposes to register any of its securities under the Securities Act for its own account as contemplated by Section 3 hereof and such securities are to be distributed by or through one or more underwriters, and if the managing underwriter of such underwritten offering shall advise the Company (in which case, the Company shall use reasonable efforts to advise the Selling Holders in writing) that if all the shares of Common Stock requested to be included in such registration were so included, then in its judgment, the number and type of securities proposed to be included in such registration would exceed the number and type of securities which could be sold in such offering within a price range acceptable to the Company, then the Company shall include in such registration pursuant to Section 3, to the extent of the number and type of securities which the Company is so advised can be sold in such offering, (A) first, securities that the Company proposes to issue and sell for its own account, (B) second, Permitted Securities requested to be registered by the holders of Permitted Securities and Registrable Common Stock requested to be registered by Piggyback Requesting Holders pursuant to Section 3	
15

 
 	 	 	hereof, pro rata among the holders of Permitted Securities and Piggyback Requesting Holders on the basis of the number of shares of Permitted Securities and Registrable Common Stock requested to be registered by all such holders of Permitted Securities and Piggyback Requesting Holders, and (C) third, other securities (other than Registrable Common Stock or Permitted Securities), if any.	 	
 	
 	(ii)	 	If the Company proposes to register any Permitted Securities pursuant to a demand registration right of the holders of Permitted Securities as contemplated by Section 3 involving an underwritten offering, and if the managing underwriter of such underwritten offering shall advise the Company (in which case, the Company shall use reasonable efforts to advise the Selling Holders in writing) that if all the shares of Common Stock requested to be included in such registration were so included, then in its judgment, the number and type of securities proposed to be included in such registration would exceed the number and type of securities which could be sold in such offering within a price range acceptable to the Company, then the Company shall include in such registration pursuant to Section 3, to the extent of the number and type of securities which the Company is so advised can be sold in such offering, (A) first, Permitted Securities requested to be registered by the holders of Permitted Securities pursuant to Section 3 hereof, pro rata among the holders of Permitted Securities on the basis of the number of shares of Permitted Securities requested to be registered by all such holders of Permitted Securities, (B) second, Registrable Common Stock requested to be registered by Piggyback Requesting Holders pursuant to Section 3 hereof, pro rata among the Piggyback Requesting Holders on the basis of the number of shares of Registrable Common Stock requested to be registered by all such Piggyback Requesting Holders, (C) third, securities that the Company proposes to issue and sell for its own account (unless the Holders of a majority of the shares of Registrable Common Stock consent to the inclusion of the Company’s securities on a pro rata basis with the Registrable Common Stock requested to be registered by Piggyback Requesting Holders pursuant to Section 3 hereof), and (D) fourth, other securities (other than Registrable Common Stock or Permitted Securities), if any.	 	
 	
 	(iii)	 	If the Company proposes to register any securities other than securities described in (i) and (ii) above, as contemplated by Section 3 involving an underwritten offering, if the managing underwriter of such underwritten offering shall advise the Company (in which case, the Company shall use reasonable efforts to advise the Selling Holders in writing) that if all the shares of Common Stock requested to be included in such registration were so included, then in its judgment, the number and type of securities proposed to be included in such registration would exceed the number and type of securities which could be sold in such offering within a price range acceptable to the Company, then the Company shall include in such	 	
16

 
 	 	 	registration pursuant to Section 3, to the extent of the number and type of securities which the Company is so advised can be sold in such offering, (A) first, Permitted Securities requested to be registered by the holders of Permitted Securities and Registrable Common Stock requested to be registered by Piggyback Requesting Holders pursuant to Section 3 hereof, pro rata among the holders of Permitted Securities and Piggyback Requesting Holders on the basis of the number of shares of Permitted Securities and Registrable Common Stock requested to be registered by all such holders of Permitted Securities and Piggyback Requesting Holders, (B) second, securities that the Company proposes to issue and sell for its own account (unless the Holders of a majority of the shares of Registrable Common Stock consent to the inclusion of the Company’s securities on a pro rata basis with the Registrable Common Stock requested to be registered by Piggyback Requesting Holders pursuant to Section 3 hereof), and (C) third, other securities (other than Registrable Common Stock and Permitted Securities), if any.	
     (c) Participation in Underwritten Registrations. The Holders of Registrable Common Stock to be distributed by underwriters in an underwritten offering contemplated by subsections (a) or (b) of this Section 6 shall be parties to the underwriting agreement between the Company and such underwriters. No Holder may participate in any underwritten registration hereunder unless such Holder (i) agrees to sell such Holder’s Registrable Common Stock on the basis provided in any such underwriting arrangements and (ii) completes and executes all questionnaires, powers of attorney, indemnities, underwriting agreements and other documents reasonably required under the terms of such underwriting agreements. The Selling Holders may, at their option, require that any or all of the representations and warranties by, and the other agreements on the part of, the Company to and for the benefit of the underwriters shall also be made to and for the benefit of such Selling Holders. No Selling Holder shall be required to make any representation or warranty to or agreement with the Company or the underwriters other than representations and warranties contained in a writing furnished by such Selling Holder expressly for use in such registration statement or agreements regarding such Selling Holder, the Selling Holder’s Registrable Common Stock and the Selling Holder’s intended method of distribution and any other representations required by law.
 	(d)	 	Holdback Agreements.	

 	(i)	 	Each Holder agrees, unless otherwise agreed to by the managing underwriter for any underwritten offering pursuant to this Agreement, not to, directly or indirectly, sell, transfer, make any short sale of, loan or effect any distribution or other disposition of any interest in any equity securities of the Company or securities convertible into or exchangeable or exercisable for equity securities of the Company, including any sale under Rule 144 under the Securities Act (each, an “Equity Transfer”), during the period (the “Holdback Period”) commencing 10 days prior to the date on which an underwritten registration pursuant to Sections 2 or 3 hereof has become effective and until (A) 180 days after the effective date of the Company’s first underwritten registered Public Offering following the	
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 	 	 	Effective Date (or such shorter period as the managing underwriter of such Public Offering may permit in writing), or (B) 90 days after the effective date of any subsequent underwritten registration, except as part of such initial underwritten registered Public Offering or any subsequent underwritten registration or to the extent that such Holder is prohibited by applicable law from agreeing to withhold securities from sale or is acting in its capacity as a fiduciary or an investment adviser. Without limiting the scope of the term “fiduciary,” a holder shall be deemed to be acting as a fiduciary or an investment adviser if its actions or the securities proposed to be sold are subject to the Employee Retirement Income Security Act of 1974, as amended, the Investment Company Act of 1940, as amended, or the Investment Advisers Act of 1940, as amended, or if such securities are held in a separate account under applicable insurance law or regulation.	 	
 	
 	(ii)	 	The Company agrees (A) not to sell, make any short sale of, loan, grant any option for the purchase of (other than employee stock options), or effect any Public Offering or distribution of any equity securities of the Company, or securities convertible into or exchangeable or exercisable for equity securities of the Company, during the 10 days prior to the date on which any underwritten registration pursuant to Sections 2 or 3 hereof has become effective and until 90 days after the effective date of such underwritten registration, except as part of such underwritten registration, and (B) to cause each holder of any equity securities, or securities convertible into or exchangeable or exercisable for equity securities, in each case, acquired from the Company at any time on or after the Effective Date (other than in a Public Offering), to agree not to sell, make any short sale of, loan, grant any option for the purchase of, or effect any Public Offering or distribution of such securities, during such period, unless the managing underwriter for any underwritten offering pursuant to this Agreement otherwise agrees.	 	

7.	 	Preparation; Confidentiality.	

 	(a)	 	Preparation. In connection with the preparation and filing of each registration statement under the Securities Act pursuant to this Agreement, the Company shall (i) give representatives (designated to the Company in writing) of each Holder or group of Holders holding at least 20% of the shares of Registrable Common Stock to be registered under such registration statement, the underwriters, if any, and one firm of counsel retained on behalf of all underwriters and one firm of counsel retained on behalf of Holders holding a majority of the shares of Registrable Common Stock covered by such registration statement, the reasonable opportunity to participate in the preparation of such registration statement, each prospectus included therein or filed with the Commission, and each amendment thereof or supplement thereto, (ii) upon reasonable advance notice to the Company, give each of them such reasonable access to all financial and other records, corporate documents and properties of the Company and its subsidiaries, as shall be necessary, in the reasonable opinion of such Holders’ and such	
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 	 	 	underwriters’ counsel, to conduct a reasonable due diligence investigation for purposes of the Securities Act, and (iii) upon reasonable advance notice to the Company, provide such reasonable opportunities to discuss the business of the Company with its officers, directors, employees and the independent public accountants who have certified its financial statements as shall be necessary, in the reasonable opinion of such Holders’ and such underwriters’ counsel, to conduct a reasonable due diligence investigation for purposes of the Securities Act.	

(b)	 	Confidentiality.	

 	(i)	 	Each Holder shall and shall cause its directors, officers, partners, managers, members, employees, advisors, agents and other representatives, including without limitation attorneys, accountants, consultants and financial advisors (collectively, “Representatives”) to maintain the confidentiality of and not to disclose any Confidential Material; provided, however, that a Holder may disclose Confidential Material (A) to such of its Representatives who need such information in connection with such Holder’s investment in securities of the Company, or (B) to the extent required by applicable law, regulation, legal process or court order.	 	
 	
 	(ii)	 	Notwithstanding the foregoing, a Holder or its Representative may disclose to any and all Persons, without limitation of any kind, the tax treatment and tax structure of the transactions contemplated hereunder and all materials of any kind (including opinions or other tax analyses) that are provided to such Holder or such Representative relating to such tax treatment and tax structure, except to the extent necessary to comply with any applicable federal or state securities laws. This authorization is not intended to permit disclosure of any other information, including, without limitation, (A) any portion of any materials to the extent not related to the tax treatment or tax structure of the transactions contemplated hereunder, (B) the identities of participants or potential participants in the transactions contemplated hereunder, (C) the existence or status of any negotiations, (D) any pricing or financial information (except to the extent such pricing or financial information is related to the tax treatment or tax structure of the transactions contemplated hereunder), or (E) any other term or detail not relevant to the tax treatment or the tax structure of the transactions contemplated hereunder. Each Holder agrees not to (directly or indirectly) trade in the Company’s securities in violation of the applicable federal and state securities laws and regulations. Each Holder shall not grant access, and the Company shall not be required to grant access, to Confidential Material under this Section 7 to any Representative who will not agree to maintain the confidentiality (to the same extent a Holder is required to maintain confidentiality) of any Confidential Material received from or otherwise made available to it by the Company or the Holders under this Agreement.	 	
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 	(iii)	 	Each Holder shall be bound by this Section 7(b) and shall remain bound until the earlier of (A) the first anniversary of the date on which such Holder is no longer a party to this Agreement, and (B) the first date on which the Confidential Material received by such Holder ceases to be Confidential Material.	

8.	 	Postponements.	

 	(a)	 	If the Company shall fail to file any registration statement required to be filed pursuant to a request for registration under Section 2(a) hereof, the Initiating Holder or Initiating Holder Group requesting such registration shall have the right to withdraw the request for registration. Any such withdrawal shall be made by giving written notice to the Company within 20 days after the date on which a registration statement would otherwise have been required to have been filed with the Commission under Section 2(a) hereof (i.e., 20 days after the date that is 90 days after the conclusion of the period within which requests for registration may be given to the Company pursuant to Section 2(a)(ii), or, if, as of such 90th day, the Company does not have the financial statements required to be included in the registration statement, 30 days after the receipt by the Company from its independent public accountants of such financial statements). In the event of such withdrawal, the request for registration shall not be counted for purposes of determining the number of registrations to which Holders are entitled pursuant to Section 2(a) hereof. The Company shall pay all Expenses incurred in connection with a request for registration withdrawn pursuant to this Section 8.	 	
 	
 	(b)	 	The Company shall not be obligated to file any registration statement, or file any amendment or supplement to any registration statement, and may suspend any Selling Holder’s rights to make sales pursuant to any effective registration statement, at any time when the Company, in the good faith and reasonably informed judgment of its Board of Directors, determines that the filing thereof at the time requested, or the offering of securities pursuant thereto, would adversely affect a pending or proposed Public Offering of the Company’s securities, a material financing, or a material acquisition, merger, recapitalization, consolidation, reorganization or similar transaction, or negotiations, discussions or pending proposals with respect thereto. The Company shall promptly give the Selling Holders written notice that such determination has been made by the Board of Directors and (if known) an estimate of the anticipated duration of the delay. The filing of a registration statement, or any amendment or supplement thereto, by the Company cannot be deferred, and any Selling Holder’s rights to make sales pursuant to an effective registration statement cannot be suspended, pursuant to the provisions of this Section 8(b) for more than 15 days after the abandonment or consummation of any of the foregoing proposals or transactions. The Company may so defer or suspend the use of any registration statement on not more than three occasions in a calendar year and for no more than a total of 90 days in a calendar year; provided that, after deferring or suspending the use of any registration statement, the Company may not again defer or suspend the use of the registration statement until a period of 30 days has elapsed after resumption of the	 	
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 	 	 	use of the registration statement. The Company shall promptly notify each Selling Holder of the expiration or earlier termination of such deferral or suspension period. If the Company suspends any Selling Holder’s rights to make sales pursuant hereto, the applicable registration period shall be extended by the number of days of such suspension.	

9.	 	Indemnification.	
     (a) Indemnification by the Company. In connection with any registration statement filed by the Company pursuant to Sections 2(a) or 3 hereof, the Company agrees to indemnify and hold harmless to the fullest extent permitted by law each Selling Holder, each other Person, if any, who controls such Selling Holder within the meaning of Section 15 of the Securities Act or Section 20 of the Exchange Act, and their respective stockholders, directors, officers, employees, partners, agents and Affiliates (each, a “Company Indemnitee” for purposes of this Section 9(a)), against any losses, claims, damages, liabilities, joint or several, actions or proceedings, whether commenced or threatened, in respect thereof and whether or not such Company Indemnitee is a party thereto, and expenses, including, without limitation, the reasonable fees, disbursements and other charges of legal counsel and reasonable costs of investigation and defense, to which such Company Indemnitee may become subject under the Securities Act or otherwise (collectively, a “Loss” or “Losses”), insofar as such Losses arise out of or are based upon any untrue statement or alleged untrue statement of any material fact contained in any registration statement under which such securities were registered or otherwise offered or sold under the Securities Act or otherwise, any preliminary prospectus, final prospectus or summary prospectus related thereto, any amendment or supplement thereto, any exhibits to the registration statement or documents or other information incorporated by reference into such registration statement or prospectus (collectively, the “Offering Documents”), or any omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements therein in the light of the circumstances in which they were made not misleading, or any violation by the Company of any federal or state law, rule or regulation applicable to the Company and relating to action required of or inaction by the Company in connection with any such registration; provided, however, the Company shall not be liable to any Company Indemnitee in any such case to the extent that any such Loss arises out of or is based upon an untrue statement or alleged untrue statement or omission or alleged omission made in such Offering Documents in reliance upon and in conformity with information furnished by such Company Indemnitee to the Company in a writing duly executed by such Company Indemnitee specifically stating that it is expressly for use therein; provided further that, the Company shall not be liable to any Person who participates as an underwriter in the offering or sale of Registrable Common Stock or any other Person, if any, who controls (within the meaning of the Exchange Act) such underwriter, in any such case to the extent that any such Loss arises out of such Person’s failure to send or give a copy of the final prospectus (including any documents incorporated by reference therein), as the same may be then supplemented or amended, to the Person asserting an untrue statement or alleged untrue statement or omission or alleged omission at or prior to the written confirmation of the sale of Registrable Common Stock to such Person if such statement or omission was corrected in such final prospectus. Such indemnity shall remain in full force and effect regardless of any investigation made by or on behalf of such Company Indemnitee and shall survive the transfer of such securities by such Company Indemnitee.

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     (b) Indemnification by the Offerors and Sellers. In connection with any registration statement filed by the Company pursuant to Sections 2(a) or 3 hereof in which a Selling Holder has registered for sale Registrable Common Stock, each such Selling Holder, severally and not jointly, agrees to indemnify and hold harmless to the fullest extent permitted by law the Company and each of its directors, officers, employees, agents, partners, stockholders, Affiliates and each other Person, if any, who controls the Company within the meaning of Section 15 of the Securities Act or Section 20 of the Exchange Act and each other seller and such seller’s directors, officers, employees, agents, partners, stockholders, Affiliates and each other Person, if any, who controls the seller within the meaning of Section 15 of the Securities Act or Section 20 of the Exchange Act (each, a “Holder Indemnitee” for purposes of this Section 9(b)), against all Losses insofar as such Losses arise out of or are based upon any untrue statement or alleged untrue statement of a material fact contained in any Offering Documents or any omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements therein in the light of circumstances in which they were made not misleading, if such untrue statement or alleged untrue statement or omission or alleged omission was made in reliance upon and in conformity with information furnished by such Selling Holder to the Company in writing duly executed by such Selling Holder specifically stating that it is expressly for use therein; provided, however, that the liability of such indemnifying party under this Section 9(b) shall be limited to the amount of the net proceeds received by such indemnifying party in the sale of Registrable Common Stock giving rise to such liability. Such indemnity shall remain in full force and effect, regardless of any investigation made by or on behalf of the Holder Indemnitee and shall survive the transfer of such securities by such indemnifying party.

     (c) Notices of Losses, etc.. Promptly after receipt by an indemnified party of written notice of the commencement of any action or proceeding involving a Loss referred to in Sections 9(a) and (b), such indemnified party will, if a claim in respect thereof is to be made against an indemnifying party, give written notice to the latter of the commencement of such action; provided, however, that the failure of any indemnified party to give notice as provided herein shall not relieve the indemnifying party of its obligations under Sections 9(a) and (b), except to the extent that the indemnifying party is materially and actually prejudiced by such failure to give notice. In case any such action is brought against an indemnified party, the indemnifying party shall be entitled to participate in and, unless in such indemnified party’s reasonable judgment a conflict of interest between such indemnified and indemnifying parties may exist in respect of such Loss, to assume and control the defense thereof, in each case at its own expense, jointly with any other indemnifying party similarly notified, to the extent that it may wish, with counsel reasonably satisfactory to such indemnified party, and after its assumption of the defense thereof, the indemnifying party shall not be liable to such indemnified party for any legal or other expenses subsequently incurred by the latter in connection with the defense thereof other than reasonable costs of investigation, unless in such indemnified party’s reasonable judgment a conflict of interest between such indemnified and indemnifying parties arises in respect of such claim after the assumption of the defense thereof. No indemnifying party shall be liable for any settlement of any such action or proceeding effected without its written consent, which shall not be unreasonably withheld. No indemnifying party shall, without the consent of the indemnified party (which consent shall not be unreasonably withheld), consent to entry of any judgment or enter into any settlement which does not include as an unconditional term thereof the giving by the claimant or plaintiff to such indemnified party of a release from all liability in respect of such

22

 

Loss or which requires action on the part of such indemnified party or otherwise subjects the indemnified party to any obligation or restriction to which it would not otherwise be subject.

     (d) Contribution. If the indemnification provided for in this Section 9 shall for any reason be unavailable to an indemnified party under Sections 9(a) or (b) in respect of any Loss, then, in lieu of the amount paid or payable under Sections 9(a) or (b), the indemnified party and the indemnifying party under Sections 9(a) or (b) shall contribute to the aggregate Losses (including legal or other expenses reasonably incurred in connection with investigating the same) (i) in such proportion as is appropriate to reflect the relative fault of the Company and the prospective Selling Holders which resulted in such Loss or action in respect thereof, with respect to the statements, omissions or actions which resulted in such Loss or action in respect thereof, as well as any other relevant equitable considerations, or (ii) if the allocation provided by clause (i) above is not permitted by applicable law, in such proportion as shall be appropriate to reflect the relative benefits received by the Company, on the one hand, and such prospective Selling Holders, on the other hand, from their sale of Registrable Common Stock; provided that, for purposes of this clause (ii), the relative benefits received by the prospective Selling Holders shall be deemed not to exceed the net proceeds received by such Selling Holders. No Person guilty of fraudulent misrepresentation (within the meaning of Section 11(f) of the Securities Act) shall be entitled to contribution from any Person who was not guilty of such fraudulent misrepresentation. The obligations, if any, of the Selling Holders to contribute as provided in this Section 9(d) are several in proportion to the relative value of their respective Registrable Common Stock covered by such registration statement and not joint. In addition, no Person shall be obligated to contribute hereunder any amounts in payment for any settlement of any action or Loss effected without such Person’s consent (provided that such consent shall not be unreasonably withheld).

     (e) Other Indemnification. The Company and each Holder who has registered for sale shares of its Registrable Common Stock shall, with respect to any required registration or other qualification of securities under any Federal or state law or regulation of any governmental authority other than the Securities Act, indemnify Holder Indemnitees and Company Indemnitees, respectively, against Losses, or, to the extent that indemnification shall be unavailable to a Holder Indemnitee or Company Indemnitee, contribute to the aggregate Losses of such Holder Indemnitee or Company Indemnitee in a manner similar to that specified in the preceding subsections of this Section 9 (with appropriate modifications).

     (f) Indemnification Payments. The indemnification and contribution required by this Section 9 shall be made by periodic payments of the amount thereof during the course of any investigation or defense, as and when any Loss is incurred and is due and payable.

10. Permitted Securities. The Company’s Board of Directors is expressly permitted to enter into agreements which provide to any holder of newly issued shares of the Company’s Common Stock rights, which are either pari passu or senior to any Holder’s rights under this Agreement, with respect to the registration of such Common Stock under the Securities Act; provided that, the performance of the obligations of the Company pursuant to such agreement shall not violate or directly conflict with any of the rights provided to the Holders or the obligations of the Company under this Agreement; provided, however, such Common Stock was issued in connection with an acquisition consummated by the Company or a new equity investment made

23

 

by such holder in the Company; provided further that, the registration rights shall only relate to the Common Stock issued in connection with such acquisition or investment and not to all of the Company’s Common Stock owned from time to time by the holders thereof. Except as expressly authorized in this Section 10, the Company shall not grant any registration rights to any Person which are pari passu or senior to the registration rights granted hereby, without the prior consent of the Holders owning a majority of the Registrable Common Stock then outstanding.

11. Adjustments Affecting Registrable Common Stock. In the event of a reorganization, recapitalization, stock split, reverse stock split, stock dividend, combination of shares, merger, consolidation, distribution of assets, or any other change in the corporate structure or securities of the Company, the Company shall make such equitable adjustments as it deems appropriate in the number and kind of shares of Registrable Common Stock held by the Holders.

12. Rule 144 and Rule 144A. The Company shall take all actions necessary to enable Holders to sell Registrable Common Stock without registration under the Securities Act within the limitation of the exemptions provided by (i) Rule 144 under the Securities Act, as such Rule may be amended from time to time, (ii) Rule 144A under the Securities Act, as such Rule may be amended from time to time, or (iii) any similar rules or regulations hereafter adopted by the Commission, including, without limiting the generality of the foregoing, filing on a timely basis all reports required to be filed under the Exchange Act. Upon the written request of any Holder, the Company shall deliver to such Holder a written statement as to whether the Company has complied with such requirements.

13. Amendments and Waivers. Any provision of this Agreement may be amended, modified or waived if, but only if, the written consent to such amendment, modification or waiver has been obtained from (i) except as provided in clauses (ii) and (iii) below, the Holder or Holders of at least a majority of the shares of Registrable Common Stock then outstanding and held by all Holders, (ii) in the case of any amendment, modification or waiver of any provision of Section 4 or Section 9 hereof or this Section 13 or any provisions as to the number of requests for registration to which holders of Registrable Common Stock are entitled under Section 2 or Section 3 hereof, the written consent of each Holder so affected, or (iii) in the case of any other amendment, modification or waiver which materially and adversely alters any right and/or obligation under this Agreement of any Holder, the Holder or Holders of at least 75% of the shares of Registrable Common Stock then outstanding and held by all Holders.

14. Nominees for Beneficial Owners. In the event that any Registrable Common Stock is held by a nominee for the beneficial owner thereof, the beneficial owner thereof may, at its election in writing delivered to the Company, be treated as the Holder of such Registrable Common Stock for purposes of any request or other action by any Holder or Holders pursuant to this Agreement or any determination of the number or percentage of shares of Registrable Common Stock held by any Holder or Holders contemplated by this Agreement. If the beneficial owner of any Registrable Common Stock so elects, the Company may require assurances reasonably satisfactory to it of such owner’s beneficial ownership of such Registrable Common Stock.

15. Assignment. The provisions of this Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective heirs, successors and permitted assigns. Any

24

 

Holder may assign to any Transferee (as permitted under applicable law) of its Registrable Common Stock its rights and obligations under this Agreement; provided that, each of the following conditions must be satisfied prior to any Transfer: (i) such Transferee shall agree in writing by executing a written joinder agreement in the form attached hereto as Schedule A (the “Joinder Agreement”) prior to the Transfer to be bound by this Agreement as if it were an original party hereto; and (ii) after giving effect to the Transfer, the Transferee would be a 10% Holder, whereupon such assignee shall for all purposes be deemed to be a Holder under this Agreement. Except as provided above or otherwise permitted by this Agreement, neither this Agreement nor any right, remedy, obligation or liability arising hereunder or by reason hereof shall be assignable by any Holder without the prior written consent of the other parties hereto. The Company may not assign this Agreement or any right, remedy, obligation or liability arising hereunder or by reason hereof.

16. Restrictions on Transfer. Each certificate held by a 10% Holder on the Effective Date shall bear the following legend:
 	 	 	“THE SECURITIES REPRESENTED BY THIS CERTIFICATE WERE ORIGINALLY ISSUED ON DECEMBER 23, 2003 PURSUANT TO THE JOINT PLAN OF REORGANIZATION UNDER CHAPTER 11 OF THE BANKRUPTCY CODE OF NRG ENERGY, INC. (THE “COMPANY”) AND CERTAIN OF ITS SUBSIDIARIES, DATED AS OF OCTOBER 10, 2003 AND CONFIRMED BY THE BANKRUPTCY COURT FOR THE SOUTHERN DISTRICT OF NEW YORK ON NOVEMBER 24, 2003. THESE SECURITIES WERE ISSUED PURSUANT TO AN EXEMPTION FROM THE REGISTRATION REQUIREMENT OF SECTION 5 OF THE SECURITIES ACT OF 1933, AS AMENDED, (THE “ACT”) PROVIDED BY SECTION 1145 OF THE BANKRUPTCY CODE, 11 U.S.C. § 1145, AND HAVE NOT BEEN REGISTERED UNDER THE ACT, AND TO THE EXTENT THAT THE HOLDER OF THESE SECURITIES IS AN “UNDERWRITER,” AS DEFINED IN SECTION 1145(b)(1) OF THE BANKRUPTCY CODE, THESE SECURITIES MAY NOT BE SOLD OR TRANSFERRED IN THE ABSENCE OF AN EFFECTIVE REGISTRATION STATEMENT UNDER THE ACT OR AN EXEMPTION FROM REGISTRATION THEREUNDER. ”	
     Upon the delivery by a 10% Holder to the Company of an opinion of counsel satisfactory to the Company that the securities represented thereby are no longer subject to the restrictions set forth in §1145(b) of the Bankruptcy Code, the Company shall remove such legend on all such certificates held by such 10% Holder.

17. Notice of Transfer. Upon the request of the Company at any time and from time to time, each Original Record Holder, each Original Other Holder, each Holder of Registrable Common Stock and each party to this Agreement shall promptly (and in any event within 8 Business Days) provide a written certification to the Company of (a) the number of shares of Common Stock owned beneficially or of record by such Person and each of its Affiliates, and (b) for requests sent by the Company within 60 days after the expiration of a Holdback Period and referring to

25

 

such Holdback Period, its compliance with the Equity Transfer restrictions set forth in Section 6(d), including information regarding each Equity Transfer made by such Person during such Holdback Period (including, without limitation, the dates of each such Equity Transfer).

18. Calculation of Percentage or Number of Shares of Registrable Common Stock. For purposes of this Agreement, all references to a percentage or number of shares of Registrable Common Stock or Common Stock shall be calculated based upon the number of shares of Registrable Common Stock or Common Stock, as the case may be, outstanding at the time such calculation is made and shall exclude any Registrable Common Stock or Common Stock, as the case may be, owned by the Company or any subsidiary of the Company. For the purposes of calculating any percentage or number of shares of Registrable Common Stock or Common Stock as contemplated by the previous sentence, the terms “10% Holder,” “Holder,” “Initiating Holder,” “Original Record Holder” and “Original Other Holder” shall include all Affiliates thereof owning any shares of Registrable Common Stock or Common Stock, except as contemplated by the definition of the term “Original Record Holder.”

19. Termination of Registration Rights. The Company’s obligations under Sections 2(a) and 3 hereof to register Common Stock for sale under the Securities Act shall terminate on the fourth anniversary of the Effective Date; provided, however, that if on such fourth anniversary any Holder is a 10% Holder, the Company’s obligations hereunder shall continue solely with respect to such 10% Holder and shall terminate when such Holder ceases to be a 10% Holder; provided further that, if the Company defers any registration and/or suspends any Selling Holder’s rights to make sales pursuant to Section 8(b), the Company’s obligations under Sections 2(a) and (3) to register Registrable Common Stock for sale under the Securities Act shall be extended by the total number of days of all such deferrals and suspensions. In addition, the Company’s obligations under this Agreement shall cease with respect to any Person when such Person (i) ceases to be a Holder or (ii) delivers to the Company a Withdrawal Notice (as hereinafter defined) in accordance with the provisions of this Section 19. Any Holder may elect, at any time and from time to time, to cause all (but not less than all) of the Registrable Common Stock held by such Holder not to be subject to this Agreement by delivery of a written notice to the Company (a “Withdrawal Notice”). Upon receipt of a Withdrawal Notice, all such shares shall no longer be deemed to be Registrable Common Stock and such Holder shall no longer be bound by or entitled to the benefits of this Agreement; provided that (except as provided below), no Holder may deliver a Withdrawal Notice during the period commencing on the date on which the Company sends such Holder written notice of its intention to effect a registration pursuant to Sections 2 or 3 hereof and until the earlier of (y) 180 days after the effective date of such registration or (z) the date on which the Company shall, in accordance with Sections 3 or 8 hereof, not register any securities with respect to which it had given written notice of its intention to register to such Holder. Notwithstanding any of the foregoing, (i) the Company’s obligations under Sections 4 and 9, (ii) the Holders’ obligations under Section 7 and (iii) both the Company and the Holders’ obligations under Section 6(d) with respect to any registration under either Section 2(a) or Section (3) which commences prior to the termination of this Agreement shall survive in accordance with their terms.

20. Miscellaneous.

26

 

     (a)  Further Assurances. Each of the parties hereto shall execute such documents and other papers and perform such further acts as may be reasonably required or advisable to carry out the provisions of this Agreement and the transactions contemplated hereby.

     (b) Headings. The headings in this Agreement are for convenience of reference only and shall not control or affect the meaning or construction of any provisions hereof.

     (c) Conflicting Instructions. If the Company receives conflicting instructions, notices or elections from two or more Persons with respect to the same Registrable Common Stock, the Company will act upon the basis of instructions, notice or election received from the registered owner of such Registrable Common Stock.

     (d) Remedies. Each Holder, in addition to being entitled to exercise all rights granted by law, including recovery of damages, will be entitled to specific performance of its rights under this Agreement. The parties hereto agree that monetary damages would not be adequate compensation for any loss incurred by reason of a breach by it of the provisions of this Agreement and the parties hereto hereby agree to waive the defense in any action for specific performance that a remedy at law would be adequate.

     (e) Entire Agreement. This Agreement constitutes the entire agreement and understanding of the parties hereto in respect of the subject matter contained herein, and there are no restrictions, promises, representations, warranties, covenants, or undertakings with respect to the subject matter hereof, other than those expressly set forth or referred to herein. This Agreement supersedes all prior agreements and understandings between the parties hereto with respect to the subject matter hereof.

     (f) Notices. Any notices or other communications to be given hereunder by any party to another party shall be in writing and shall be delivered personally, by telecopy, by certified or registered mail, postage prepaid, return receipt requested, or by Federal Express or other comparable delivery service, as follows: (i) if to the Company, to:

NRG Energy, Inc.
Attention: General Counsel
901 Marquette Avenue
Minneapolis, Minnesota 55402

Tel: (612) 373-5300
Fax: (612) 373-5392

with a copy to:

Kirkland & Ellis LLP
Attention: Margaret A. Gibson, P.C.
200 East Randolph Drive
Chicago, Illinois 60601

Tel: (312) 861-2000
Fax: (312) 861-2200

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(ii) if to a Holder, to the address of such Holder as set forth in the signature pages hereto, or (iii) to such other address as the party to whom notice is to be given may provide in a written notice to the other parties hereto, a copy of which shall be on file with the Secretary of the Company. Notice shall be effective when delivered if given personally, when receipt is acknowledged if telecopied, three days after mailing if given by registered or certified mail as described above, and one Business Day after deposit if given by Federal Express or comparable delivery service.

     (g) Governing Law. This Agreement shall be governed by and construed in accordance with the laws of the State of New York.

     (h) Severability. Notwithstanding any provision of this Agreement, neither the Company nor any other party hereto shall be required to take any action which would be in violation of any applicable Federal or state securities law. The invalidity or unenforceability of any provision of this Agreement in any jurisdiction shall not affect the validity, legality or enforceability of any other provision of this Agreement in such jurisdiction or the validity, legality or enforceability of this Agreement, including any such provision, in any other jurisdiction, it being intended that all rights and obligations of the parties hereunder shall be enforceable to the fullest extent permitted by law.

     (i) Counterparts. This Agreement may be executed in two or more counterparts, each of which shall be deemed an original but all of which shall constitute one and the same Agreement.

[REMAINDER OF PAGE LEFT BLANK INTENTIONALLY]

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     IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first above written.
 	 	 	 	 	
 	 	NRG ENERGY, INC.	
 	 	 	 	 	
 	 	By:	 	 	

 	
 	 	 	 	Name:	
 	 	 	 	Title:	

 

     IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first above written.
 	 	 	 	 	
 	 	HOLDER:
 	
 	 	By:	 	 	

 	
 	 	 	 	Name:

	
 	 	 	 	Title:

	
 	 	 	 	 
Number of Shares of Common Stock Owned:

 	
 	 	 	 	Address:

	

 	

 	
 	 	 	 	Telephone No.:

	
 	 	 	 	Facsimile No.:

	

 

SCHEDULE A

REGISTRATION RIGHTS AGREEMENT

Joinder Agreement

     The undersigned is executing and delivering this Joinder Agreement pursuant to the Registration Rights Agreement dated as of           (as the same may hereafter be amended, the “Agreement”), among NRG Energy, Inc., a Delaware corporation (the “Company”), and the other persons named as parties therein. Capitalized terms used herein and not defined herein have the meanings set forth in the Agreement.

     By executing and delivering this Joinder Agreement to the Company, the undersigned hereby agrees to become a party to, to be bound by, and to comply with the provisions of the Agreement in the same manner as if the undersigned were a Holder of Registrable Common Stock as an original signatory to the Agreement, and the undersigned’s            shares of Common Stock shall be included as Registrable Common Stock under the Agreement.

     Accordingly, the undersigned has executed and delivered this Joinder Agreement as of the             day of      ,  200.
 	 	 	 	 	
 	 	HOLDER:	
 	 	 	 	 	
 	 	By:	 	 	

 	
 	 	 	 	Name:	

 	
 	 	 	 	Title:	

 	
 	 	 	 	Number of Shares of Common Stock Owned:

 	 	 	 	

 	
 	 	 	 	Address:	

 	

 	

 	
 	 	 	 	Telephone No.:	

 	
 	 	 	 	Facsimile No.:	

 	

 

SCHEDULE B

ELECTION FORM
 	 	 	
o	 	I do not wish to be a party to the Registration Rights Agreement between NRG Energy, Inc., a Delaware corporation (“NRG”), and other Holders (the “Registration Rights Agreement”). (If you check this box, skip ahead to the bottom of this Election Form, date and sign it at the bottom and return it to the addresses listed in the letter above.)	

o	 	I hereby confirm that I am an Original Record Holder or an Original Other Holder and that I, and each of my Affiliates (if any) named below, wish to become parties to the Registration Rights Agreement. (If you check this box, please complete the remainder of this Election Form, date and sign it at the bottom and return it to the addresses listed in the letter above.)	

Name and Address of Beneficial Owner	 	 	 	 	
 	 	 	 	Number of shares	
(Please provide information for you	 	Contact phone and	 	of Common Stock	
and each of your Affiliates, if any)

	 	facsimile numbers

	 	held beneficially

	
This Election Form must be completed and signed by you and each of your Affiliates (if any) listed above. Please use additional pages as necessary.
 	 	 	
Name of Beneficial Owner:	 	 	

 	
By:	 	 	

 	
 	 	(authorized signature)	
Printed Name:	 	 	

 	
Title:	 	 	

 	
Date:	 	 	

 	

 

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

     We hereby consent to the incorporation by reference in the Registration Statement on Form S-8 (No. 333-114007) of NRG Energy, Inc. of our reports dated March 10, 2004, except as to Notes 6, 20, 30 and 31 which are as of October 29, 2004, relating to the NRG Energy, Inc. consolidated financial statements and financial statement schedules, which appear in this Form 10-K Amendment No. 2.

/s/ PricewaterhouseCoopers LLP  	 	 	
PricewaterhouseCoopers LLP 	 	 	
 	
Minneapolis, Minnesota
November 3, 2004

 

EXHIBIT 31.1

CERTIFICATION

I, David Crane, certify that:

     1. I have reviewed this annual report on Form 10-K/A 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)) for the registrant and have:

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

     (b) Omitted pursuant to SEC Release 33-8238;

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

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

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

     (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: November 2, 2004

 

EXHIBIT 31.2

CERTIFICATION

I, Robert Flexon, certify that:

     1. I have reviewed this annual report on Form 10-K/A 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)) for the registrant and have:

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

     (b) Omitted pursuant to SEC Release 33-8238;

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

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

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

     (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 FLEXON
                                                         
Robert Flexon
Chief Financial Officer
(Principal Financial Officer)

Date: November 2, 2004

 

EXHIBIT 31.3

CERTIFICATION

I, James Ingoldsby, certify that:

     1. I have reviewed this annual report on Form 10-K/A 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)) for the registrant and have:

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

     (b) Omitted pursuant to SEC Release 33-8238;

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

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

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

     (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 INGOLDSBY
                                                         
James Ingoldsby
Vice President and Controller
(Principal Accounting Officer)

Date: November 2, 2004

 

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 Annual Report of NRG Energy, Inc. (the Company) on Form 10-K/A for the year ended December 31, 2003, as filed with the Securities and Exchange Commission on the date hereof (Form 10-K/A), 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-K/A 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-K/A 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-K/A.

Date: November 2, 2004

/s/ DAVID CRANE
                                                         
David Crane,
Chief Executive Officer
(Principal Executive Officer)

/s/ ROBERT FLEXON
                                                         
Robert Flexon
Chief Financial Officer
(Principal Financial Officer)

/s/ JAMES INGOLDSBY
                                                         
James Ingoldsby
Vice President and 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.

 

EXHIBIT 99.2

LOUISIANA GENERATING LLC

FINANCIAL STATEMENTS

At December 31, 2003, December 6, 2003 and
December 31, 2002, and for the Period from
December 6, 2003 to December 31, 2003, the Period
from January 1, 2003 to December 5, 2003 and for
the Years Ended December 31, 2002 and 2001

 

LOUISIANA GENERATING LLC

INDEX
 	 	 	 	 	
 	 	Page(s)	
Reports of Independent Auditors	 	 	2–3	 	
Financial Statements	 	 	 	 	
Balance Sheets at December 31, 2003, December 6, 2003 and December 31, 2002	 	 	4	 	
Statements of Operations for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001	 	 	5	 	
Statements of Member’s Equity for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001	 	 	6	 	
Statements of Cash Flows for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001	 	 	7	 	
Notes to Financial Statements	 	 	8–33	 	
Reports of Independent Auditors on Financial Statement Schedule	 	 	34–35	 	
Financial Statement Schedule	 	 	36	 	
1

 

REPORT OF INDEPENDENT AUDITORS

To the Member of
Louisiana Generating LLC

      In our opinion, the accompanying balance sheet and the related statements of operations, of member’s equity and of cash flows present fairly, in all material respects, the financial position of Louisiana Generating LLC (“Predecessor Company”) at December 31, 2002, and the results of its operations and its cash flows for the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      As discussed in Note 1 to the financial statements, on May 14, 2003, NRG Energy, Inc. and certain of its subsidiaries including the Company, filed a petition with the United States Bankruptcy Court for the Southern District of New York for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. NRG Energy, Inc.’s Plan of Reorganization was substantially consummated on December 5, 2003, and Reorganized NRG emerged from bankruptcy. The Company emerged from bankruptcy on December 23, 2003, pursuant to a separate plan of reorganization referred to as the Northeast/ South Central Plan of Reorganization. The impact of NRG Energy, Inc.’s emergence from bankruptcy and fresh start accounting was applied to the Company on December 5, 2003 under push down accounting methodology.

      As discussed in Note 20 to the financial statements, the Company has restated its previously issued financial statements for the years ended December 31, 2002 and 2001 to reflect an income tax provision (benefit) and deferred taxes.
 	 	
 	/s/ PRICEWATERHOUSECOOPERS LLP	

	
 	PricewaterhouseCoopers LLP	
Minneapolis, Minnesota
March 10, 2004

2

 

REPORT OF INDEPENDENT AUDITORS

To the Member of
Louisiana Generating LLC

      In our opinion, the accompanying balance sheets and the related statements of operations, of member’s equity and of cash flows present fairly, in all material respects, the financial position of Louisiana Generating LLC (“Reorganized Company”) at December 31, 2003 and December 6, 2003, and the results of its operations and its cash flows for the period from December 6, 2003 to December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      As discussed in Note 1 to the financial statements, on May 14, 2003, NRG Energy, Inc. and certain of its subsidiaries including the Company, filed a petition with the United States Bankruptcy Court for the Southern District of New York for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. NRG Energy, Inc.’s Plan of Reorganization was substantially consummated on December 5, 2003, and Reorganized NRG emerged from bankruptcy. The Company emerged from bankruptcy on December 23, 2003, pursuant to a separate plan of reorganization referred to as the Northeast/ South Central Plan of Reorganization. The impact of NRG Energy, Inc.’s emergence from bankruptcy and fresh start accounting was applied to the Company on December 5, 2003 under push down accounting methodology.
 	 	
 	/s/ PRICEWATERHOUSECOOPERS LLP	

	

 	PricewaterhouseCoopers LLP	
Minneapolis, Minnesota
March 10, 2004

3

 

LOUISIANA GENERATING LLC

BALANCE SHEETS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	 	 	 	(As Restated)	
 	 	 	
 	 	(In thousands of dollars)	
ASSETS	
Current assets	 	 	 	 	 	 	 	 	 	 	 	 	
 	Cash and cash equivalents	 	$	4,612	 	 	$	11,141	 	 	$	—	 	
 	Restricted cash	 	 	99	 	 	 	133,793	 	 	 	109,336	 	
 	Accounts receivable	 	 	37,039	 	 	 	37,712	 	 	 	46,089	 	
 	Accounts receivable — affiliates	 	 	3,812	 	 	 	6,669	 	 	 	—	 	
 	Note receivable	 	 	584	 	 	 	1,500	 	 	 	3,000	 	
 	Inventory	 	 	34,077	 	 	 	39,402	 	 	 	63,394	 	
 	Current deferred income taxes	 	 	—	 	 	 	—	 	 	 	85	 	
 	Prepayments and other current assets	 	 	6,588	 	 	 	8,001	 	 	 	2,927	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total current assets	 	 	86,811	 	 	 	238,218	 	 	 	224,831	 	
Property, plant and equipment, net of accumulated depreciation of $2,452, $0 and $75,357, respectively	 	 	863,096	 	 	 	865,219	 	 	 	964,220	 	
Intangible assets, net of accumulated amortization of $787, $0 and $123, respectively	 	 	120,854	 	 	 	121,641	 	 	 	1,662	 	
Debt issuance costs, net of accumulated amortization of $0, $0 and $1,179, respectively	 	 	—	 	 	 	—	 	 	 	9,540	 	
Decommissioning fund investments	 	 	4,809	 	 	 	4,809	 	 	 	4,617	 	
Other assets	 	 	685	 	 	 	663	 	 	 	612	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total assets	 	$	1,076,255	 	 	$	1,230,550	 	 	$	1,205,482	 	

	 	 	 	

	 	 	 	

	 	
LIABILITIES AND MEMBER’S EQUITY	
Current liabilities	 	 	 	 	 	 	 	 	 	 	 	 	
 	Current portion of long-term debt payable to affiliate	 	$	—	 	 	$	750,750	 	 	$	750,750	 	
 	Accounts payable	 	 	10,430	 	 	 	14,543	 	 	 	13,560	 	
 	Accounts payable — affiliates	 	 	—	 	 	 	—	 	 	 	59,558	 	
 	Accrued interest — affiliates	 	 	—	 	 	 	15,296	 	 	 	55,413	 	
 	Other current liabilities	 	 	18,433	 	 	 	32,649	 	 	 	11,355	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total current liabilities	 	 	28,863	 	 	 	813,238	 	 	 	890,636	 	
Burdensome contracts	 	 	387,524	 	 	 	390,510	 	 	 	—	 	
Deferred income taxes	 	 	—	 	 	 	—	 	 	 	37,896	 	
Other long-term obligations	 	 	9,789	 	 	 	9,619	 	 	 	6,238	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total liabilities	 	 	426,176	 	 	 	1,213,367	 	 	 	934,770	 	

	 	 	 	

	 	 	 	

	 	
Commitments and contingencies	 	 	 	 	 	 	 	 	 	 	 	 	
Member’s equity	 	 	650,079	 	 	 	17,183	 	 	 	270,712	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total liabilities and member’s equity	 	$	1,076,255	 	 	$	1,230,550	 	 	$	1,205,482	 	

	 	 	 	

	 	 	 	

	 	
The accompanying notes are an integral part of these financial statements.

4

 

LOUISIANA GENERATING LLC

STATEMENTS OF OPERATIONS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	 	 	 	(As Restated)	 	(As Restated)	
 	 	 	
 	 	(In thousands of dollars)	
Revenues	 	$	27,886	 	 	$	355,984	 	 	$	399,458	 	 	$	401,935	 	
Operating costs	 	 	19,351	 	 	 	254,124	 	 	 	281,190	 	 	 	273,245	 	
Depreciation and amortization	 	 	2,452	 	 	 	28,916	 	 	 	29,671	 	 	 	27,211	 	
General and administrative expenses	 	 	1,868	 	 	 	8,997	 	 	 	5,284	 	 	 	6,601	 	
Reorganization items	 	 	104	 	 	 	20,241	 	 	 	—	 	 	 	—	 	
Restructuring charges	 	 	—	 	 	 	—	 	 	 	208	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	Income (loss) from operations	 	 	4,111	 	 	 	43,706	 	 	 	83,105	 	 	 	94,878	 	
Other income (expense), net	 	 	99	 	 	 	336	 	 	 	779	 	 	 	(334	)	
Interest expense	 	 	(3,442	)	 	 	(66,067	)	 	 	(71,220	)	 	 	(72,665	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	Income (loss) before income taxes	 	 	768	 	 	 	(22,025	)	 	 	12,664	 	 	 	21,879	 	
Income tax expense (benefit)	 	 	312	 	 	 	(8,776	)	 	 	8,687	 	 	 	8,759	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	Net income (loss)	 	$	456	 	 	$	(13,249	)	 	$	3,977	 	 	$	13,120	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
The accompanying notes are an integral part of these financial statements.

5

 

LOUISIANA GENERATING LLC

STATEMENTS OF MEMBER’S EQUITY
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	Accumulated	 	 	
 	 	Member	 	Member	 	Accumulated	 	Other	 	Total	

	 	Contributions/	 	Net Income	 	Comprehensive	 	Member’s	
 	 	Units	 	Amount	 	Distributions	 	(Loss)	 	Income	 	Equity	

	 	

	 	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Balances at December 31, 2000 (Predecessor Company) (As Restated)	 	 	1,000	 	 	$	1	 	 	$	187,225	 	 	$	13,744	 	 	$	—	 	 	$	200,970	 	
Cumulative effect upon adoption of SFAS No. 133	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	500	 	 	 	500	 	
Impact of SFAS No. 133 for the year ending December 31, 2001	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(500	)	 	 	(500	)	
Net income	 	 	—	 	 	 	—	 	 	 	—	 	 	 	13,120	 	 	 	—	 	 	 	13,120	 	

	 	
Comprehensive income for 2001	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	13,120	 	
Contribution from member	 	 	—	 	 	 	—	 	 	 	5,051	 	 	 	—	 	 	 	—	 	 	 	5,051	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Balances at December 31, 2001 (Predecessor Company) (As Restated)	 	 	1,000	 	 	 	1	 	 	 	192,276	 	 	 	26,864	 	 	 	—	 	 	 	219,141	 	
Net income and comprehensive income	 	 	—	 	 	 	—	 	 	 	—	 	 	 	3,977	 	 	 	—	 	 	 	3,977	 	
Contribution from member	 	 	—	 	 	 	—	 	 	 	47,594	 	 	 	—	 	 	 	—	 	 	 	47,594	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Balances at December 31, 2002 (Predecessor Company) (As Restated)	 	 	1,000	 	 	 	1	 	 	 	239,870	 	 	 	30,841	 	 	 	—	 	 	 	270,712	 	
Net loss and comprehensive loss	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(13,249	)	 	 	—	 	 	 	(13,249	)	
Contribution from member	 	 	—	 	 	 	—	 	 	 	88,999	 	 	 	—	 	 	 	—	 	 	 	88,999	 	
Balances at December 5, 2003 (Predecessor Company)	 	 	1,000	 	 	 	1	 	 	 	328,869	 	 	 	17,592	 	 	 	—	 	 	 	346,462	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Push down accounting adjustment	 	 	—	 	 	 	—	 	 	 	(311,687	)	 	 	(17,592	)	 	 	—	 	 	 	(329,279	)	
Balances at December 6, 2003 (Reorganized Company)	 	 	1,000	 	 	 	1	 	 	 	17,182	 	 	 	—	 	 	 	—	 	 	 	17,183	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Contribution from member	 	 	—	 	 	 	—	 	 	 	632,440	 	 	 	—	 	 	 	—	 	 	 	632,440	 	
Net income and comprehensive income	 	 	—	 	 	 	—	 	 	 	—	 	 	 	456	 	 	 	—	 	 	 	456	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Balances at December 31, 2003 (Reorganized Company)	 	 	1,000	 	 	$	1	 	 	$	649,622	 	 	$	456	 	 	$	—	 	 	$	650,079	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
The accompanying notes are an integral part of these financial statements.

6

 

LOUISIANA GENERATING LLC

STATEMENTS OF CASH FLOWS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	 	 	 	(As Restated)	 	(As Restated)	
 	 	 	
 	 	(In thousands of dollars)	
Cash flows from operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	$	456	 	 	$	(13,249	)	 	$	3,977	 	 	$	13,120	 	
Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Depreciation and amortization	 	 	2,452	 	 	 	28,916	 	 	 	29,671	 	 	 	27,211	 	
 	Deferred income taxes	 	 	312	 	 	 	(8,776	)	 	 	8,687	 	 	 	8,759	 	
 	Restructuring and impairment charges	 	 	—	 	 	 	9,141	 	 	 	50	 	 	 	—	 	
 	Amortization of debt issuance costs	 	 	—	 	 	 	399	 	 	 	441	 	 	 	427	 	
 	Amortization of out-of-market power contracts	 	 	(2,199	)	 	 	—	 	 	 	—	 	 	 	—	 	
 	Changes in assets and liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Accounts receivable	 	 	673	 	 	 	8,788	 	 	 	(2,736	)	 	 	9,291	 	
 	 	Inventory	 	 	5,325	 	 	 	16,689	 	 	 	(11,408	)	 	 	(27,772	)	
 	 	Prepayments and other current assets	 	 	1,413	 	 	 	(5,074	)	 	 	(559	)	 	 	(838	)	
 	 	Accounts payable	 	 	(4,113	)	 	 	983	 	 	 	(12,869	)	 	 	9,819	 	
 	 	Accounts payable and receivable — affiliates, net	 	 	2,857	 	 	 	(66,227	)	 	 	76,360	 	 	 	(54,896	)	
 	 	Accrued interest — affiliates	 	 	(15,296	)	 	 	(40,117	)	 	 	34,960	 	 	 	(844	)	
 	 	Other current liabilities	 	 	(14,216	)	 	 	14,123	 	 	 	1,505	 	 	 	4,895	 	
 	 	Other assets and liabilities	 	 	(164	)	 	 	7,752	 	 	 	344	 	 	 	286	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	Net cash (used in) provided by operating activities	 	 	(22,500	)	 	 	(46,652	)	 	 	128,423	 	 	 	(10,542	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Cash flows from investing activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Capital expenditures	 	 	(329	)	 	 	(8,057	)	 	 	(12,231	)	 	 	(8,866	)	
Decrease (increase) in note receivable	 	 	916	 	 	 	1,500	 	 	 	(3,000	)	 	 	—	 	
Increase in trust funds	 	 	—	 	 	 	(192	)	 	 	—	 	 	 	—	 	
Decrease (increase) in restricted cash	 	 	133,694	 	 	 	(24,457	)	 	 	(109,336	)	 	 	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	Net cash provided by (used in) investing activities	 	 	134,281	 	 	 	(31,206	)	 	 	(124,567	)	 	 	(8,866	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Cash flows from financing activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Contributions by members	 	 	632,440	 	 	 	88,999	 	 	 	47,594	 	 	 	5,051	 	
Net proceeds/payments on revolver	 	 	—	 	 	 	—	 	 	 	(40,000	)	 	 	40,000	 	
Payment of note payable — affiliate	 	 	(750,750	)	 	 	—	 	 	 	(12,750	)	 	 	(25,250	)	
Checks in excess of cash	 	 	—	 	 	 	—	 	 	 	(1,908	)	 	 	—	 	
Debt issuance costs	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(331	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	Net cash (used in) provided by financing activities	 	 	(118,310	)	 	 	88,999	 	 	 	(7,064	)	 	 	19,470	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	Net change in cash and cash equivalents	 	 	(6,529	)	 	 	11,141	 	 	 	(3,208	)	 	 	62	 	
Cash and cash equivalents	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Beginning of period	 	 	11,141	 	 	 	—	 	 	 	3,208	 	 	 	3,146	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
End of period	 	$	4,612	 	 	$	11,141	 	 	$	—	 	 	$	3,208	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Supplemental disclosures of cash flow information	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash paid for interest	 	$	29,999	 	 	$	105,785	 	 	$	36,260	 	 	$	73,035	 	
The accompanying notes are an integral part of these financial statements.

7

 

LOUISIANA GENERATING LLC

NOTES TO FINANCIAL STATEMENTS

1.     Organization

      Louisiana Generating LLC (“Louisiana Generating” or the “Company”) is an indirect wholly owned subsidiary of NRG Energy, Inc. (“NRG Energy”). NRG South Central LLC (“South Central”) owns 100% of the Company. South Central’s members are NRG Central U.S. LLC (“NRG Central”) and South Central Generation Holding LLC (“South Central Generation”). NRG Central and South Central Generation are directly held wholly owned subsidiaries of NRG Energy, each of which owns a 50% interest in South Central.

      The Company was formed for the purpose of acquiring, owning, operating and maintaining the electric generating facilities acquired from Cajun Electric Power Cooperative, Inc. (“Cajun Electric”). Pursuant to a competitive bidding process, following the Chapter 11 bankruptcy proceeding of Cajun Electric, Louisiana Generating acquired the non-nuclear electric power generating assets of Cajun Electric.

 	Recent Developments	
      On May 14, 2003, NRG Energy and 25 of its direct and indirect wholly owned subsidiaries commenced voluntary petitions under Chapter 11 of the bankruptcy code in the United States Bankruptcy Court for the Southern District of New York. The Company was included in the Chapter 11 filing. During the bankruptcy proceedings, NRG Energy continued to conduct business and manage the companies as debtors in possession pursuant to sections 1107(a) and 1108 of the bankruptcy code. Two plans of reorganization were filed in connection with the restructuring efforts. The first, filed on May 14, 2003, and referred to as NRG Energy’s Plan of Reorganization, relates to NRG Energy and the other NRG Energy plan debtors. The second plan, relating to the Company, the NRG Northeast Generating LLC subsidiaries and the other South Central subsidiaries, referred to as the Northeast/ South Central Plan of Reorganization, was filed on September 17, 2003. On November 24, 2003, the bankruptcy court entered an order confirming NRG Energy’s Plan of Reorganization and the plan became effective on December 5, 2003. On November 25, 2003, the bankruptcy court issued an order confirming the Northeast/ South Central Plan of Reorganization and the plan became effective on December 23, 2003. In connection with NRG Energy’s emergence from bankruptcy, NRG Energy adopted fresh start accounting in accordance with AICPA Statement of Position 90-7,  Financial Reporting by Entities in Reorganization Under the Bankruptcy Code  (“SOP 90-7”) on December 5, 2003. NRG Energy’s fresh start accounting was applied to the Company on a push down accounting basis with the financial statement impact recorded as an adjustment to the December 6, 2003, member’s equity in the amount of $329.3 million.

 	NRG Energy’s Plan of Reorganization	
      NRG Energy’s Plan of Reorganization is the result of several months of intense negotiations among NRG Energy, Xcel Energy, Inc. (“Xcel Energy”) and the two principal committees representing NRG Energy creditor groups, referred to as the Global Steering Committee and the Noteholder Committee. A principal component of NRG Energy’s Plan of Reorganization is a settlement with Xcel Energy in which Xcel Energy agreed to make a contribution consisting of cash (and, under certain circumstances, its stock) in the aggregate amount of up to $640 million to be paid in three separate installments following the effective date of NRG Energy’s Plan of Reorganization. The Xcel Energy settlement agreement resolves any and all claims existing between Xcel Energy and NRG Energy and/or its creditors and, in exchange for the Xcel Energy contribution, Xcel Energy is receiving a complete release of claims from NRG Energy and its creditors, except for a limited number of creditors who have preserved their claims as set forth in the confirmation order entered on November 24, 2003.

 	Northeast/South Central Plan of Reorganization	
      The Northeast/ South Central Plan of Reorganization was proposed on September 17, 2003 after necessary financing commitments were secured. On November 25, 2003, the bankruptcy court issued an order

8

 
LOUISIANA GENERATING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

confirming the Northeast/ South Central Plan of Reorganization and the plan became effective on December 23, 2003. In connection with the order confirming the Northeast/ South Central Plan of Reorganization, the court entered a separate order which provides that the allowed amount of the bondholders’ claims shall equal in the aggregate the sum of (i) $1.3 billion plus (ii) any accrued and unpaid interest at the applicable contract rates through the date of payment to the indenture trustee plus (iii) the reasonable fees, costs or expenses of the collateral agent and indenture trustee (other than reasonable professional fees incurred from October 1, 2003) plus (iv) $19.6 million, ratably, for each holder of bonds based upon the current outstanding principal amount of the bonds and irrespective of (a) the date of maturity of the bonds, (b) the interest rate applicable to such bonds and (c) the issuer of the bonds.

      The creditors of Northeast and South Central subsidiaries were unimpaired by the Northeast/ South Central Plan of Reorganization. The creditors holding allowed general secured claims were paid in cash, in full on the effective date of the Northeast/ South Central Plan of Reorganization. Holders of allowed unsecured claims will receive or have received either (i) cash equal to the unpaid portion of their allowed unsecured claim, (ii) treatment that leaves unaltered the legal, equitable and contractual rights to which such unsecured claim entitles the holder of such claim, (iii) treatment that otherwise renders such unsecured claim unimpaired pursuant to section 1124 of the bankruptcy code or (iv) such other, less favorable treatment that is confirmed in writing as being acceptable to such holder and to the applicable debtor.

2.	Summary of Significant Accounting Policies	

 	NRG Energy Fresh Start Reporting/Push Down Accounting	
      In accordance with SOP 90-7, certain companies qualify for fresh start (“Fresh Start”) reporting in connection with their emergence from bankruptcy. Fresh Start reporting is appropriate on the emergence from Chapter 11 if the reorganization value of the assets of the emerging entity immediately before the date of confirmation is less than the total of all post-petition liabilities and allowed claims, and if the holders of existing voting shares immediately before confirmation receive less than 50% of the voting shares of the emerging entity. NRG Energy met these requirements and adopted Fresh Start reporting and applied push down accounting to its various subsidiary operations including the Company. Under push down accounting, the Company’s equity fair value was allocated to the Company’s assets and liabilities based on their estimated fair values as of December 5, 2003, as further described in Note 3.

      Under the requirements of Fresh Start, NRG Energy adjusted its assets and liabilities, other than deferred income taxes, to their estimated fair values as of December 5, 2003. As a result of marking the assets and liabilities to their estimated fair values, NRG Energy determined that there was a negative reorganization value that was reallocated back to the tangible and intangible assets. Deferred taxes were determined in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 109,  Accounting for Income Taxes . The net effect of all Fresh Start adjustments resulted in a gain of $3.9 billion, which is reflected in NRG Energy’s Predecessor Company results for the period from January 1, 2003 to December 5, 2003. The application of the Fresh Start provisions of SOP 90-7 created a new reporting entity having no retained earnings or accumulated deficit.

      As part of the bankruptcy process, NRG Energy engaged an independent financial advisor to assist in the determination of its reorganized enterprise value. The fair value calculation was based on management’s forecast of expected cash flows from its core assets. Management’s forecast incorporated forward commodity market prices obtained from a third party consulting firm. A discounted cash flow calculation was used to develop the enterprise value of Reorganized NRG, determined in part by calculating the weighted average cost of capital of the Reorganized NRG. The Discounted Cash Flow, or “DCF,” valuation methodology equates the value of an asset or business to the present value of expected future economic benefits to be generated by that asset or business. The DCF methodology is a “forward looking” approach that discounts expected future economic benefits by a theoretical or observed discount rate. The independent financial

9

 
LOUISIANA GENERATING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

advisor prepared a 30-year cash flow forecast using a discount rate of approximately 11%. The resulting reorganization enterprise value as included in the Disclosure Statement ranged from $5.5 billion to $5.7 billion. The independent financial advisor then subtracted NRG Energy’s project level debt and made several other adjustments to reflect the values of assets held for sale, excess cash and collateral requirements to estimate a range of Reorganized NRG equity value of between $2.2 billion and $2.6 billion.

      In constructing the Fresh Start balance sheet upon emergence from bankruptcy, NRG Energy used a reorganization equity value of approximately $2.4 billion, as NRG Energy believed this value to be the best indication of the value of the ownership distributed to the new equity owners. NRG Energy’s Plan of Reorganization provided for the issuance of 100,000,000 shares of NRG Energy common stock to the various creditors resulting in a calculated price per share of $24.04. The reorganization value of approximately $9.1 billion was determined by adding the reorganized equity value of $2.4 billion, $3.7 billion of interest bearing debt and other liabilities of $3.0 billion. The reorganization value represents the fair value of an entity before liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after restructuring. This value is consistent with the voting creditors and Court’s approval of NRG Energy’s Plan of Reorganization.

      The application of SOP 90-7 and push down accounting resulted in the creation of a new reporting entity for the Company. Consequently, the financial statements of the Reorganized Company and the Predecessor Company are separated by a black line to distinguish that the assets, liabilities and member’s equity as well as the results of operations are not comparable between periods. Under the requirements of push down accounting, the Company has adjusted its assets and liabilities to their estimated fair values as of December 5, 2003. The impact of push down accounting resulted in the reduction of member’s equity for the Company in the amount of $329.3 million.

      Between May 14, 2003 and December 23, 2003, the Company operated as a debtor in possession under the supervision of the bankruptcy court. The financial statements for reporting periods within that timeframe were prepared in accordance with the provisions of SOP 90-7.

      For financial reporting purposes, close of business on December 5, 2003, represents the date of NRG Energy’s emergence from bankruptcy. As previously stated, the Company emerged from bankruptcy on December 23, 2003. The accompanying financial statements reflect the impact of NRG Energy’s emergence from bankruptcy effective December 5, 2003. As used herein, the following terms refer to the Company and its operations:
 	 	 	
“Predecessor Company”	 	The Company, prior to push down accounting	
 	 	The Company’s operations, January 1, 2001 - December 31, 2001	
 	 	The Company’s operations, January 1, 2002 - December 31, 2002	
 	 	The Company’s operations, January 1, 2003 - December 5, 2003	
“Reorganized Company”	 	The Company, post push down accounting	
 	 	The Company’s operations, December 6, 2003 - December 31, 2003	
      The bankruptcy court in its confirmation order approved NRG Energy’s Plan of Reorganization on November 24, 2003, and subsequently approved the Company’s Plan of Reorganization on December 23, 2002. Under the requirements of SOP 90-7, the Fresh Start date is determined to be the confirmation date unless significant uncertainties exist regarding the effectiveness of the bankruptcy order. NRG Energy’s Plan of Reorganization required completion of the Xcel Energy settlement agreement prior to emergence from bankruptcy. Management believes this settlement agreement was a significant contingency and thus delayed the Fresh Start date until the Xcel Energy settlement agreement was finalized on December 5, 2003.

10

 
LOUISIANA GENERATING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

 	Cash and Cash Equivalents	
      Cash and cash equivalents include highly liquid investments with a maturity of three months or less at the time of purchase.

 	Restricted Cash	
      Restricted cash consists primarily of funds held in trust accounts to satisfy the requirements of certain debt agreements. The restricted cash balance was $0.1 million, $133.8 million and $109.3 million at December 31, 2003, December 6, 2003 and December 31, 2002, respectively.

 	Inventory	
      Inventory consists principally of coal, spare parts and fuel oil and is valued at the lower of weighted average cost or market.

 	Property, Plant and Equipment	
      Property, plant and equipment are stated at cost; however, impairment adjustments are recorded whenever events or changes in circumstances indicate carrying values may not be recoverable. At December 5, 2003, the Company recorded adjustments to the property, plant and equipment to reflect such items at fair value in accordance with push down accounting. A new cost basis was established with those adjustments. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance that do not improve or extend the life of the respective asset are charged to expense as incurred. Depreciation is computed using the straight-line method over the estimated useful lives of the asset. The assets and related accumulated depreciation amounts are adjusted for asset retirements and disposals with the resulting gain or loss included in operations.

 	Asset Impairments	
      Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate carrying values may not be recoverable. Such reviews were performed in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144,  Accounting for the Impairment or Disposal of Long-Lived Assets . An impairment loss is recognized if the total future estimated undiscounted cash flows expected from an asset are less than its carrying value. An impairment charge is measured by the difference between an asset’s carrying amount and fair value. Fair values may be determined by a variety of valuation methods, including appraisals, sales prices of similar assets and present value techniques.

 	Debt Issuance Costs	
      Debt issuance costs consist of legal and other costs incurred to obtain debt financing. These costs, which were written off as part of push down accounting (see Note 3), were capitalized and amortized as interest expense on a basis which approximates the effective interest method over the terms of the related debt.

 	Intangible Assets	
      Intangible assets represent contractual rights held by the Company. Intangible assets are amortized over their economic useful life and reviewed for impairment on a periodic basis.

      Intangible assets consist primarily of the fair value of power sales agreements and emission allowances. The amounts related to the power sales agreements will be amortized as a reduction to revenue over the terms and conditions of each contract. Emission allowance related amounts will be amortized as additional fuel expense based upon the actual level of emissions from the respective plant through 2023.

11

 
LOUISIANA GENERATING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

      Effective January 1, 2002, the Company implemented SFAS No. 142, Goodwill and Other Intangible Assets. Pursuant to SFAS No. 142, goodwill is not amortized but is subject to periodic testing. At December 31, 2003, December 6, 2003 and December 31, 2002, the Company had no goodwill recorded in the financial statements.

 	Burdensome Contracts	
      As part of push down accounting, the Company recognized liabilities for executory contracts (power sales agreements) related to the sale of electric capacity and energy in future periods, where the fair value was determined to be significantly burdensome as compared to market expectations. These liabilities represent the out-of-market portion of the executory contracts and are not an indication of the entire fair value of the contracts. Therefore, the liability is being amortized as an increase to revenue over the terms and conditions of each underlying contract.

 	Revenue Recognition	
      Revenues from the sale of electricity are recorded based upon the output delivered and capacity provided at rates specified under contract terms or prevailing market rates. Under fixed-price contracts, revenues are recognized as products or services are delivered. Revenues and related costs under cost reimbursable contract provisions are recorded as costs are incurred. Capacity and ancillary revenue is recognized when contractually earned. Disputed revenues are not recorded in the financial statements until disputes are resolved and collection is assured.

 	Power Marketing Activities	
      The Company has entered into an agency agreement with a marketing affiliate for the sale of energy, capacity and ancillary services produced and for the procurement and management of emission credit allowances, which enables the affiliate to engage in forward sales and hedging transactions to manage the Company’s electricity price exposure. Net gains or losses on hedges by the marketing affiliate, which are physically settled, are recognized in the same manner as the hedged item. The Company receives the net transaction price on all contracts that are physically settled by its marketing affiliate.

 	Income Taxes	
      The Company has been organized as a limited liability company. Therefore, federal and state income taxes are assessed at the member level. However, a provision for separate company federal and state income taxes has been reflected in the accompanying financial statements (see Note 20 — Income Taxes). As a result of the Company being included in the NRG Energy consolidated tax return and tax payments, federal and state taxes payable amounts resulting from the tax provision are reflected as a contribution by member in the statement of member’s equity and the balance sheet.

      Deferred income taxes are recognized for the tax consequences in future years of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts at each period end based on enacted tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. Income tax expense is the tax payable for the period and the change during the period in deferred tax assets and liabilities. A valuation allowance is recorded to reduce deferred tax assets to the amount more likely than not to be realized.

 	Concentrations of Credit Risk	
      Financial instruments, which potentially subject the Company to concentrations of credit risk, consist primarily of cash, accounts receivable and notes receivable. Cash accounts are generally held in federally

12

 
LOUISIANA GENERATING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

insured banks. Accounts receivable and notes receivable are concentrated within entities engaged in the energy industry. These industry concentrations may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. Receivables are generally not collateralized; however, the Company believes the credit risk posed by industry concentration is offset by the diversification and creditworthiness of its customer base.

 	Fair Value of Financial Instruments	
      The carrying amount of cash and cash equivalents, receivables, accounts payables, and accrued liabilities approximate fair value because of the short maturity of these instruments. The fair value of long-term debt is estimated based on quoted market prices and similar instruments with equivalent credit quality.

 	Use of Estimates in Financial Statements	
      The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenue and expenses during the reporting period. Actual results may differ from those estimates.

      In recording transactions and balances resulting from business operations, the Company uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, uncollectible accounts and the valuation of long-term energy commodities contracts, among others. In addition, estimates are used to test long-lived assets for impairment and to determine fair value of impaired assets. As better information becomes available (or actual amounts are determinable), the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

 	Reclassifications	
      Certain prior year amounts have been reclassified for comparative purposes. These reclassifications had no effect on net income or total member’s equity as previously reported.

3.	Emergence from Bankruptcy and Fresh Start Reporting	
      In accordance with the requirements of push down accounting, the Company’s fair value of $17.2 million was allocated to the Company’s assets and liabilities based on their individual estimated fair values. A third party was used to complete an independent appraisal of the Company’s tangible assets, intangible assets and contracts.

      The determination of the fair value of the Company’s assets and liabilities was based on a number of estimates and assumptions, which are inherently subject to significant uncertainties and contingencies.

      Due to the adoption of push down accounting as of December 5, 2003, the Reorganized Company’s balance sheets, statements of operations and cash flows have not been prepared on a consistent basis with the Predecessor Company’s financial statements and are not comparable in certain respects to the financial statements prior to the application of push down accounting. A black line has been drawn on the accompanying financial statements to separate and distinguish between the Reorganized Company and the

13

 
LOUISIANA GENERATING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

Predecessor Company. The effects of the push down accounting adjustments on the Company’s balance sheet as of December 5, 2003, were as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor	 	 	 	Reorganized	
 	 	Company	 	 	 	Company	

	 	 	 	

	
 	 	December 5,	 	Push Down	 	December 6,	
 	 	2003	 	Adjustments	 	2003	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
ASSETS	
Current assets	 	 	 	 	 	 	 	 	 	 	 	 	
 	Cash and cash equivalents	 	$	11,141	 	 	$	—	 	 	$	11,141	 	
 	Restricted cash	 	 	133,793	 	 	 	—	 	 	 	133,793	 	
 	Accounts receivable	 	 	37,301	 	 	 	411	(A)	 	 	37,712	 	
 	Accounts receivable — affiliates	 	 	6,669	 	 	 	—	 	 	 	6,669	 	
 	Notes receivable — current	 	 	1,500	 	 	 	—	 	 	 	1,500	 	
 	Inventory	 	 	46,705	 	 	 	(7,303	)(B)	 	 	39,402	 	
 	Current deferred income taxes	 	 	118	 	 	 	(118	)(C)	 	 	—	 	
 	Prepayments and other current assets	 	 	8,001	 	 	 	—	 	 	 	8,001	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total current assets	 	 	245,228	 	 	 	(7,010	)	 	 	238,218	 	
Property, plant and equipment, net	 	 	938,963	 	 	 	(73,744	)(D)	 	 	865,219	 	
Intangible assets	 	 	1,605	 	 	 	120,036	(E)	 	 	121,641	 	
Decommissioning fund investments	 	 	4,809	 	 	 	—	 	 	 	4,809	 	
Other assets	 	 	663	 	 	 	—	 	 	 	663	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total assets	 	$	1,191,268	 	 	$	39,282	 	 	$	1,230,550	 	

	 	 	 	

	 	 	 	

	 	
 	
LIABILITIES AND MEMBER’S EQUITY	
Current liabilities	 	 	 	 	 	 	 	 	 	 	 	 	
 	Current portion of long-term debt payable to affiliate	 	$	750,750	 	 	$	—	 	 	$	750,750	 	
 	Accounts payable	 	 	14,543	 	 	 	—	 	 	 	14,543	 	
 	Accrued interest — affiliates	 	 	15,296	 	 	 	—	 	 	 	15,296	 	
 	Other current liabilities	 	 	29,273	 	 	 	3,376	(A)	 	 	32,649	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total current liabilities	 	 	809,862	 	 	 	3,376	 	 	 	813,238	 	
Burdensome contracts	 	 	—	 	 	 	390,510	(E)	 	 	390,510	 	
Deferred income taxes	 	 	29,120	 	 	 	(29,120	)(C)	 	 	—	 	
Other long-term obligations	 	 	5,824	 	 	 	3,795	(A)	 	 	9,619	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total liabilities	 	 	844,806	 	 	 	368,561	 	 	 	1,213,367	 	

	 	 	 	

	 	 	 	

	 	
Member’s equity	 	 	 	 	 	 	 	 	 	 	 	 	
 	Member’s contributions	 	 	328,870	 	 	 	(311,687	)	 	 	17,183	 	
 	Accumulated net income	 	 	17,592	 	 	 	(17,592	)	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total member’s equity	 	 	346,462	 	 	 	(329,279	)(F)	 	 	17,183	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total liabilities and member’s equity	 	$	1,191,268	 	 	$	39,282	 	 	$	1,230,550	 	

	 	 	 	

	 	 	 	

	 	

 
 	 	 	
(A)	 	Miscellaneous adjustments and reclasses resulting from the Company’s bankruptcy settlement. This includes Revaluation of Asset Retirement Obligations (“ARO”) of $1.7 million and a $5.7 million	
14

 
LOUISIANA GENERATING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

adjustment to post-retirement and other benefit obligations in order to reflect the accumulated benefit obligation liability based on independent actuarial reports.

(B)	 	Accounting policy change upon adoption of push down accounting. Consumables are no longer included as inventory and are expensed as incurred.	
 	 	 	
(C)	 	Reflects the adjustment to deferred income tax assets and liabilities due to push down accounting.	
 	 	 	
(D)	 	Result of allocating the equity value in conformity with the purchase method of accounting for business combinations. These allocations were based on valuations obtained from independent appraisers.	
 	 	 	
(E)	 	Reflects management’s estimate, with the assistance of independent appraisers, of the fair value of power sales agreements and SO2 emission credits. Management identified certain power sales agreements that were either significantly valuable or significantly burdensome as compared to our market expectations.	
 	 	 	
(F)	 	The change in member’s equity reflects the fair value adjustments resulting from NRG Energy’s Fresh Start accounting procedures.	

4.	Other Charges	
      Restructuring charges, and reorganization items included in operating costs and expenses in the statements of operations include the following:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Year	
 	 	2003 to	 	2003 to	 	Ended	
 	 	December 31,	 	December 5,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Reorganization items	 	$	104	 	 	$	20,241	 	 	$	—	 	
Restructuring charges	 	 	—	 	 	 	—	 	 	 	208	 	

	 	 	 	

	 	 	 	

	 	
 	 	$	104	 	 	$	20,241	 	 	$	208	 	

	 	 	 	

	 	 	 	

	 	
15

 
LOUISIANA GENERATING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

 	Reorganization Items	
      In connection with the confirmation of the Northeast/ South Central Plan of Reorganization, the debt held by the Company became an allowable claim. As a result, the Company incurred a charge of approximately $9.1 million to write-off related debt issuance costs as well as incurring a pre-payment charge of approximately $11.3 million for the anticipated refinancing transaction completed with the emergence from bankruptcy of the Company. Both items were expensed in November 2003, as they were determined to be an allowed claim at that time.
 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	Predecessor	
 	 	Company	 	Company	

	 	

	
 	 	For the	 	For the	
 	 	Period from	 	Period from	
 	 	December 6,	 	January 1,	
 	 	2003 to	 	2003 to	
 	 	December 31,	 	December 5,	
 	 	2003	 	2003	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Reorganization items	 	 	 	 	 	 	 	 	
 	Legal and advisor fees related to bankruptcy	 	$	104	 	 	$	615	 	
 	Deferred financing costs	 	 	—	 	 	 	9,141	 	
 	Pre-payment charge	 	 	—	 	 	 	11,261	 	
 	Interest earned on accumulated cash	 	 	—	 	 	 	(776	)	

	 	 	 	

	 	
 	 	Total reorganization items	 	$	104	 	 	$	20,241	 	

	 	 	 	

	 	

 	Restructuring Charges	
      The Company incurred $208,000 in 2002 of severance costs associated with the combining of various functions and restructuring costs consisting of advisor fees. These costs were recorded as restructuring charges in the statements of operations.

5.	Inventory	
      Inventory, which is valued at the lower of weighted average cost or market, consists of:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Coal	 	$	26,108	 	 	$	31,342	 	 	$	48,001	 	
Spare parts	 	 	7,186	 	 	 	7,220	 	 	 	14,553	 	
Fuel oil	 	 	783	 	 	 	840	 	 	 	840	 	

	 	 	 	

	 	 	 	

	 	
 	Total inventory	 	$	34,077	 	 	$	39,402	 	 	$	63,394	 	

	 	 	 	

	 	 	 	

	 	
16

 
LOUISIANA GENERATING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

6.	Property, Plant and Equipment	
      The major classes of property, plant and equipment were as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Predecessor	 	 	
 	 	Average	 	Reorganized Company	 	Company	 	 	
 	 	Remaining	 	

	 	

	 	 	
 	 	Useful	 	December 31,	 	December 6,	 	December 31,	 	Depreciable	
 	 	Life	 	2003	 	2003	 	2002	 	Lives	

	 	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Land	 	 	 	 	 	$	20,142	 	 	$	20,142	 	 	$	3,733	 	 	 	 	 	
Facilities, machinery and equipment	 	 	17 years	 	 	 	845,077	 	 	 	845,077	 	 	 	1,030,747	 	 	 	1-35 years	 	
Office furnishings and equipment	 	 	3 years	 	 	 	—	 	 	 	—	 	 	 	4,109	 	 	 	1-5 years	 	
Construction in progress	 	 	 	 	 	 	329	 	 	 	—	 	 	 	988	 	 	 	 	 	
Accumulated depreciation	 	 	 	 	 	 	(2,452	)	 	 	—	 	 	 	(75,357	)	 	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	 	 	
Property, plant and equipment, net	 	 	 	 	 	$	863,096	 	 	$	865,219	 	 	$	964,220	 	 	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	 	 	

7.	Asset Retirement Obligation	
      Effective January 1, 2003, the Company adopted SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires an entity to recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred. Upon initial recognition of a liability for an asset retirement obligation, an entity shall capitalize an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes and written or oral contracts, including obligations arising under the doctrine of promissory estoppel.

      The Company identified certain retirement obligations within its operations. These asset retirement obligations are related primarily to the future dismantlement of equipment on leased property and environment obligations related to ash disposal site closures. The Company also identified similar other asset retirement obligations that could not be calculated because the assets associated with the retirement obligations were determined to have an indeterminate life. The adoption of SFAS No. 143 resulted in recording a $0.2 million increase to property, plant and equipment and a $0.3 million increase to other long-term obligations. The cumulative effect of adopting SFAS No. 143 was recorded as a $21,000 increase to depreciation expense and a $0.1 million increase to operating costs in the period from January 1, 2003 to December 5, 2003, as the Company considered the cumulative effect to be immaterial.

17

 
LOUISIANA GENERATING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

      The following represents the balances of the asset retirement obligation as of January 1, 2003, and the additions and accretion of the asset retirement obligation for the period from January 1, 2003 to December 5, 2003 and the period from December 6, 2003 to December 31, 2003, which is included in other long-term obligations in the balance sheet. As a result of applying push down accounting, the Company revalued the asset retirement obligations on December 5, 2003. The Company recorded an additional asset retirement obligation of $1.7 million in connection with push down accounting. This amount results from a change in the discount rate used between the date of adoption and December 5, 2003, equal to 500 to 600 basis points.

 	 	Predecessor Company	

	
 	 	 	 	Accretion	 	 	
 	 	Beginning	 	 	 	for Period	 	Adjustment	 	Ending	
 	 	Balance	 	 	 	Ended	 	for Fresh	 	Balance	
 	 	January 1,	 	Liabilities	 	December 5,	 	Start	 	December 5,	
 	 	2003	 	Incurred	 	2003	 	Reporting	 	2003	

	 	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Asset retirement obligations	 	$	291	 	 	$	—	 	 	$	42	 	 	$	1,718	 	 	$	2,051	 	

 	 	Reorganized Company	

	
 	 	 	 	Accretion for	 	 	
 	 	 	 	Period	 	 	
 	 	Beginning	 	December 6	 	Ending	
 	 	Balance	 	to	 	Balance	
 	 	December 6,	 	December 31,	 	December 31,	
 	 	2003	 	2003	 	2003	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Asset retirement obligations	 	$	2,051	 	 	$	12	 	 	$	2,063	 	
      The following represents the pro-forma effect on the Company’s net income for the period from January 1, 2003 to December 5, 2003, and for the years ended December 31, 2002 and 2001, as if the Company had adopted SFAS No. 143 as of January 1, 2001:

 	 	Predecessor Company	

	
 	 	For the	 	 	
 	 	Period from	 	 	
 	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	December 31,	
 	 	December 5,	 	

	
 	 	2003	 	2002	 	2001	

	 	

	 	

	
 	 	 	 	(As Restated)	 	(As Restated)	
 	 	 	
 	 	(In thousands of dollars)	
Net (loss) income as reported	 	$	(13,249	)	 	$	3,977	 	 	$	13,120	 	
Pro forma adjustment to reflect retroactive adoption of SFAS No. 143	 	 	70	 	 	 	(28	)	 	 	(42	)	

	 	 	 	

	 	 	 	

	 	
Pro forma net (loss) income after taxes	 	$	(13,179	)	 	$	3,949	 	 	$	13,078	 	

	 	 	 	

	 	 	 	

	 	
      On a pro forma basis, an asset retirement obligation of $0.3 million and $0.3 million would have been recorded as an other long-term obligation at January 1, 2002 and December 31, 2002, respectively, based on similar assumptions used to determine the amounts on the balance sheet at December 6, 2003 and December 31, 2003.

8.	Intangible Assets	
      During the first quarter of 2002, the Company adopted SFAS No. 142, Goodwill and other Intangible Assets, which requires new accounting for intangible assets, including goodwill. Intangible assets with finite lives will be amortized over their economic useful lives and periodically reviewed for impairment. Goodwill will no longer be amortized, but will be tested for impairment annually and on an interim basis if an event occurs or a circumstance changes between annual tests that may reduce the fair value of a reporting unit below

18

 
LOUISIANA GENERATING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

its carrying value. The Company did not recognize any asset impairments as a result of adopting SFAS No. 142. Upon the application of push down accounting, the Company established certain contract based intangibles, which will be amortized over their respective contractual lives.

 	Reorganized Company	
      The Company had intangible assets with a net carrying value of $120.9 million and $121.6 million at December 31, 2003 and December 6, 2003, respectively. The power sales agreement amounts will be amortized as a reduction to revenue over the terms and conditions of each contract. The remaining amortization period is four years for the power sales agreements. Emission allowances will be amortized as additional fuel expense based upon the actual level of emissions from the respective plants through 2023. No amortization was recorded during the period from December 6, 2003 to December 31, 2003, as this balance includes only emission allowances for 2004 and beyond. All emission allowances for 2003 were used prior to December 5, 2003. The amortization expense for the period from December 6, 2003 to December 31, 2003, was $0.8 million related to power sales agreements. The annual aggregate amortization expense for each of the five succeeding years is expected to approximate $12.6 million in years one through four, and $5.7 million in year five for both the power sales agreements and emission allowances. Intangible assets in the Reorganized Company consisted of the following:

 	 	Reorganized Company	

	
 	 	 	 	 	
 	 	December 31, 2003	 	December 6, 2003	

	 	

	
 	 	Gross	 	 	 	Gross	 	 	
 	 	Carrying	 	Accumulated	 	Carrying	 	Accumulated	
 	 	Amount	 	Amortization	 	Amount	 	Amortization	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Intangible assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Power sales agreements	 	$	27,800	 	 	$	787	 	 	$	27,800	 	 	$	—	 	
 	Emission allowances	 	 	93,841	 	 	 	—	 	 	 	93,841	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total intangible assets	 	$	121,641	 	 	$	787	 	 	$	121,641	 	 	$	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	

 	Predecessor Company	
      At December 31, 2002, the Company had intangible assets of $1.7 million. For the period from January 1, 2003 to December 5, 2003, and for the years ended December 31, 2002 and 2001, the Company recorded approximately $0, $123,000 and $78,000 of amortization expense, respectively. The net amount of the intangible assets was transferred to fixed assets as part of Fresh Start reporting.

9.	Long-Term Debt	
      On March 30, 2000, South Central issued $800 million of senior secured bonds in two traunches. The first traunche was for $500 million with a coupon of 8.962% and a maturity of 2016. The second traunch was for $300 million with a coupon of 9.479% and a maturity of 2024. Interest on the bonds is payable in arrears on each March 15 and September 15. Principal payments are due semi-annually on each March 15 and September 15 with $25,500,000 due in 2002 and 2003, $15,000,000 due in 2004, 2005 and 2006. The remaining $667,500,000 matures between March 15, 2007 and September 15, 2024. The proceeds of the bonds were used to finance the Company’s acquisition of the Cajun Generating facilities on March 31, 2000. Effective March 30, 2000, South Central and the Company entered into a guarantor loan agreement that provides for substantially the same terms and conditions of the bonds.

      On December 13, 2000, South Central commenced an exchange offer of these bonds with registered bonds that contained similar terms and conditions. The exchange offer closed on January 19, 2001, with all bonds being exchanged.

19

 
LOUISIANA GENERATING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

      On September 16, 2002, the Company failed to make approximately $47 million in combined principal and interest payments on the 8.962% Series A-1 senior secured bonds due 2016 and 9.479% Series B-1 senior secured bonds due 2024. The Company had 15 days to make principal and interest payments to the Company’s A-1 and B-1 Series bond holders to avoid an event of default on these bonds. The 15 day grace period to make payment ended October 1, 2002, and the Company did not make the required payments. As a result, the Company was in default on these bonds. On November 21, 2002, the bond trustee, on behalf of bondholders, accelerated the approximately $750 million of debt under the South Central facility, rendering the debt immediately due and payable. In January 2003, the South Central bondholders unilaterally withdrew $35.6 million from a restricted revenue account relating to the September 15, 2002, interest payment and fees. On March 17, 2003, semi-annual principal and interest of approximately $47 million came due. An amount of $34.4 million was withdrawn from a restricted revenue account relating to the interest portion of this payment, and the approximately $12.8 million principal portion was deferred. As a result of the Company’s failure to make the September 16, 2002, principal and interest payment and other default provisions, the entire $750.8 million owed was classified as a current liability at December 6, 2003 and December 31, 2002.

      On December 23, 2003, NRG Energy issued $1.25 billion in Second Priority Notes, due and payable on December 15, 2013. On the same date, NRG Energy also entered into a new credit facility for up to $1.45 billion. Proceeds of the December 23, 2003, Second Priority Note issuance and the new credit facility were used among other things, for repayment of secured debt held by the Company. The Company used proceeds of $632.1 million from a capital contribution from NRG Energy and cash on hand to pay the outstanding balance of $750.8 million, along with $15.3 million in accrued interest and $11.3 million in pre-payment charges.

10.	Derivative Instruments and Hedging Activity	
      On January 1, 2001, the Company adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 137, SFAS No. 138 and SFAS No. 149. SFAS No. 133 requires the Company to record all derivatives on the balance sheet at fair value. Changes in the fair value of nonhedge derivatives will be immediately recognized in earnings. The criteria used to determine if hedge accounting treatment is appropriate are (a) the designation of the hedge to an underlying exposure, (b) whether or not the overall risk is being reduced and (c) if there is high degree of correlation between the value of the derivative instrument and the underlying obligation. Formal documentation of the hedging relationship, the nature of the underlying risk, the risk management objective, and the means by which effectiveness will be assessed is created at the inception of the hedge. Changes in fair values of derivatives accounted for as hedges will either be recognized in earnings as offsets to the changes in fair value of related hedged assets, liabilities and firm commitments or, for forecasted transactions, deferred and recorded as a component of other accumulated comprehensive income, or “OCI,” until the hedged transactions occur and are recognized in earnings. The ineffective portion of a hedging derivative instrument’s change in fair value will be immediately recognized in earnings. The Company also formally assesses both at inception and at least quarterly thereafter, whether the derivatives that are used in hedging transactions are highly effective in offsetting the changes in either the fair value or cash flows of the hedged item. This assessment includes all components of each derivative’s gain or loss unless otherwise noted. When it is determined that a derivative ceases to be a highly effective hedge, hedge accounting is discontinued.

      SFAS No. 133 applies to South Central’s energy and energy related commodities financial instruments, long-term power sales contracts and long-term fuel purchase contracts used to mitigate variability in earnings due to fluctuations in spot market prices, hedge fuel requirements at generation facilities and protect investment in fuel inventories. The Company does not enter into long-term power sales contracts, long-term fuel purchase contracts, or other derivative instruments. However, the Company does enter into long-term contracts that are exempt from SFAS No. 133. Derivative activities are conducted by an affiliate of South Central and are not recorded by the Company.

20

 
LOUISIANA GENERATING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

11.	Financial Instruments	
      The estimated fair values of the Company’s recorded financial instruments are as follows:

 	 	Reorganized Company	 	Predecessor Company	

	 	

	
 	 	 	 	 	 	 	
 	 	December 31, 2003	 	December 6, 2003	 	December 31, 2002	

	 	

	 	

	
 	 	Carrying	 	Fair	 	Carrying	 	Fair	 	Carrying	 	Fair	
 	 	Amount	 	Value	 	Amount	 	Value	 	Amount	 	Value	

	 	

	 	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Cash	 	$	4,612	 	 	$	4,612	 	 	$	11,141	 	 	$	11,141	 	 	$	—	 	 	$	—	 	
Restricted cash	 	 	99	 	 	 	99	 	 	 	133,793	 	 	 	133,793	 	 	 	109,336	 	 	 	109,336	 	
Notes receivable	 	 	584	 	 	 	584	 	 	 	1,500	 	 	 	1,500	 	 	 	3,000	 	 	 	3,000	 	
Decommissioning funds	 	 	4,809	 	 	 	4,809	 	 	 	4,809	 	 	 	4,809	 	 	 	4,617	 	 	 	4,617	 	
Current portion of long-term assets	 	 	—	 	 	 	—	 	 	 	750,750	 	 	 	750,750	 	 	 	750,750	 	 	 	525,525	 	
      For cash and cash equivalents and restricted cash, the carrying amount approximates fair value because of the short-term maturity of those instruments. The fair value of notes receivable approximates carrying value as the underlying instruments bear a variable market interest rate. The fair value of long-term debt is estimated based on the quoted market prices for similar issues. Decommissioning fund investments are comprised of various debt securities of the United States of America and are carried at amortized cost, which approximates their fair value.

12.	Related Party Transactions	
      The Company has a power sales and agency agreement with NRG Power Marketing Inc., (“NRG Power Marketing”) a wholly owned subsidiary of NRG Energy. The agreement is effective until December 31, 2030. Under the agreement, NRG Power Marketing will (i) have the exclusive right to manage, market and sell all power not otherwise sold or committed to by the Company, (ii) procure and provide to the Company all fuel required to operate its facilities and (iii) market, sell and purchase all emission credits owned, earned or acquired by the Company. In addition, NRG Power Marketing will have the exclusive right and obligation to direct the power output from the facilities.

      Under the agreement, NRG Power Marketing pays to the Company gross receipts generated through sales, less costs incurred by NRG Power Marketing relative to its providing services (e.g. transmission and delivery costs, fuel cost, taxes, employee labor, contract services, etc.). The Company incurs no fees related to these power sales and agency agreements with NRG Power Marketing.

      The Company has an operation and maintenance agreement with NRG Operating Services, Inc. (“NRG Operating Services”), a wholly owned subsidiary of NRG Energy. The agreement is perpetual in term until terminated in writing by the Company or until earlier terminated upon an event of default. Under the agreement, at the request of the Company, NRG Operating Services manages, oversees and supplements the operation and maintenance of the Cajun facilities.

      During the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001, the Company incurred no operating costs from NRG Operating Services.

      The Company and South Central each entered into an agreement with NRG Energy for corporate support and services. The agreement is perpetual in term until terminated in writing by the Company or South Central or until earlier terminated upon an event of default. Under the agreement, NRG Energy will provide services, as requested, in areas such as human resources, accounting, finance, treasury, tax, office administration, information technology, engineering, construction management, environmental, legal and safety. Under

21

 
LOUISIANA GENERATING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

the agreement, NRG Energy is paid for personnel time as well as out-of-pocket costs. These costs are reflected in general and administrative expenses in the statements of operations.

      During the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003, and for the years ended December 31, 2002 and 2001, the Company incurred approximately $1.2 million, $3.2 million, $0.2 million and $0.6 million, respectively, for corporate support and services.

      At December 31, 2003, December 6, 2003 and December 31, 2002, the Company had an accounts payable — affiliates balance of approximately $0, $0 and $59.6 million and an accounts receivable — affiliates balance of $3.8 million, $6.7 million and $0, respectively. The affiliate payable amounts consisted primarily of a payable to NRG Energy for development costs incurred related to the acquisition of the Cajun Facilities and other expenses paid on the Company’s behalf as described in the paragraphs above. The affiliates receivable amounts consisted primarily of net receipts due from NRG Power Marketing.

      During 2002, Louisiana Generating sold 50% of its interest in a natural gas line to its affiliate Big Cajun I Peakers at a gain of $0.4 million.

13.	Benefits Disclosures	
      The Company retained a number of the administrative and operating personnel of Cajun Electric upon acquisition of Cajun Electric’s generating facilities. Prior to March 31, 2000, these employees were participants in the National Rural Electric Cooperative Association’s Retirement and Security Program, a master multiple-employer defined benefit plan. Effective March 31, 2000, the Cooperative’s defined benefit and 401(k) plans were terminated and no ongoing pension obligation was assumed by the Company or NRG Energy. The Company sponsors a cash balance pension plan arrangement whereby the employees are entitled to a pension benefit of approximately 7% of total payroll. The employees are also eligible to participate in a 401(k) plan that provides for the matching of specified amounts of employee contributions to the plan.

      For the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001, the Company recorded approximately $0.14 million, $0.64 million, $0.36 million and $0.26 million of pension expense and approximately $28,000, $0.4 million, $0.7 million and $0.5 million, respectively, of 401(k) matching funds.

14.	Sales to Significant Customers	
      For the period from December 6, 2003 to December 31, 2003, sales to two customers, Southwest Louisiana Electric Membership Corporation and Dixie Electric Membership Corporation, accounted for 16.8% and 16.6%, respectively of the Company’s total revenues. For the period from January 1, 2003 to December 5, 2003, sales to two customers, Southwest Louisiana Electric Membership Corporation and Dixie Electric Membership Corporation, accounted for 18.3% and 17.5%, respectively of the Company’s total revenues. For the year ended December 31, 2002, sales to two customers, Southwest Louisiana Electric Membership Corporation and Dixie Electric Membership Corporation, accounted for 16.8% and 15.9%, respectively of the Company’s total revenues. For the year ended December 31, 2001, sales to two customers, Southwest Louisiana Electric Membership Corporation and Dixie Electric Membership Corporation, accounted for 16.4% and 15.7%, respectively of the Company’s total revenues. During March 2000, the Company entered into certain power sales agreements with 11 distribution cooperatives that were customers of Cajun Electric prior to the acquisition of the Cajun Facilities. The initial terms of these agreements provide for the sale of energy, capacity and ancillary services for periods ranging from 4 to 25 years. In addition, the Company assumed Cajun Electric’s obligations under four long-term power supply agreements. The terms of these agreements range from 10 to 26 years. These power sales agreements accounted for the 82.7%, 85.0%, 80.2% and 78.4%, respectively, of the Company’s total revenues during the period from December 6, 2003 to

22

 
LOUISIANA GENERATING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

December 31, 2003, the period from January 1, 2003 to December 5, 2003, and for the years ended December 31, 2002 and 2001, respectively.

15.	Commitments and Contingencies	

 	Operating Lease Commitments	
      The Company leases certain of its equipment under operating leases expiring on various dates through 2006. Rental expense under these operating leases was approximately $14,000 and $0.2 million for the period from December 6, 2003 to December 31, 2003 and for the period from January 1, 2003 to December 5, 2003, and $0.2 million and $0.2 million for the years ended December 31, 2002 and 2001, respectively. Future minimum lease commitments under these leases for the years ending after December 31, 2003, are as follows:
 	 	 	 	 	
 	 	(In thousands	
 	 	of dollars)	
2004	 	$	101	 	
2005	 	 	31	 	
2006	 	 	3	 	

 	Contractual Commitments	

 	Power Supply Agreements with the Distribution Cooperatives	
      During March 2000, the Company entered into certain power supply agreements with 11 distribution cooperatives to provide energy, capacity and transmission services. The agreements are standardized into three types, Form A, B and C. In connection with push down accounting resulting from NRG Energy’s fresh start accounting, certain of the Company’s long-term power supply agreements were determined to be at above or below market rates. As a result, the Company valued these agreements and recognized the fair value of such contracts on the December 6, 2003 balance sheet. The fair value of these contracts that were deemed to be valuable have been included in intangible assets. The fair value of contracts determined to be significantly burdensome were recorded as noncurrent liabilities. The favorable and unfavorable contract valuation amounts will be amortized as a net increase to revenues over the terms and conditions of each contract. These contracts consist primarily of the long-term power sale agreements the Company has with its cooperative customers and certain others. The gross carrying amount of the unfavorable out-of-market power sales agreements at both December 31, 2003 and December 6, 2003, was $390.5 million, respectively. During the period from December 6, 2003 to December 31, 2003, approximately $3.0 million was amortized as an increase to revenues.

 	Form A Agreements	
      Six of the distribution cooperatives entered into Form A power supply agreements. The Form A agreement is an all-requirements power supply agreement which has an initial term of 25 years, commencing on March 31, 2000. After the initial term, the agreement continues on a year-to-year basis, unless terminated by either party giving five years advanced notice.

      Under the Form A power supply agreement, the Company is obligated to supply the distribution cooperative all of the energy and capacity required by the distribution cooperative for service to its retail customers although the distribution cooperative has certain limited rights under which it can purchase energy and capacity from third parties.

      The Company must contract for all transmission service required to serve the distribution cooperative and will pass through the costs of transmission service to the cooperative. The Company is required to supply at its

23

 
LOUISIANA GENERATING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

cost, without pass through, control area services and ancillary services which transmission providers are not required to provide.

      The Company owns and maintains the substations and other facilities used to deliver energy and capacity to the distribution cooperative and charges the cooperative a monthly specific delivery facility charge for such facilities any additions to, or new delivery facilities. The initial monthly charge is 1% of the value of all of the distribution cooperative’s specific delivery facilities. The cost of additional investment during the term of the agreement will be added to the initial value of the delivery facilities to calculate the monthly specific delivery facility charge.

      The Company charges the distribution cooperative a demand charge, a fuel charge and a variable operation and maintenance charge. The demand charge consists of two components, a capital rate and a fixed operation and maintenance rate. The distribution cooperatives have an option to choose one of two fuel options, all six have selected the first option which is a fixed fee through 2004 and determined using a formula which is based on gas prices and the cost of delivered coal for the period thereafter. At the end of the fifteenth year of the contract, the cooperatives may switch to the second fuel option. The second fuel option consists of a pass-through of fuel costs, with a guaranteed coal heat rate and purchased energy costs, excluding the demand component in purchased power. From time to time the Company may offer fixed fuel rates which the cooperative may elect to utilize. The variable operation and maintenance charge is fixed through 2004 and escalates at either approximately 3% per annum or in accordance with actual changes in specified indices as selected by the distribution cooperative. Five of the distribution cooperatives elected the fixed escalation provision and one elected the specified indices provision.

 	Form B Agreements	
      One distribution cooperative selected the Form B Power Supply Agreement. The term of the Form B power supply agreement commences on March 31, 2000 and ends on December 31, 2024. The Form B power supply agreement allows the distribution cooperative the right to elect to limit its purchase obligations to “base supply” or also to purchase “supplemental supply.” Base supply is the distribution cooperative’s ratable share of the generating capacity purchased by the Company from Cajun Electric. Supplemental supply is the cooperative’s requirements in excess of the base supply amount. The distribution cooperative which selected the Form B agreement also elected to purchase supplemental supply.

      The Company charges the distribution cooperative a monthly specific delivery facility charge of approximately 1.75% of the depreciated net book value of the specific delivery facilities, including additional investment. The distribution cooperative may assume the right to maintain the specific delivery facilities and reduce the charge to 1.25% of the depreciated net book value of the specific delivery facilities. The Company also charges the distribution cooperative its ratable share of 1.75% of the depreciated book value of common delivery facilities, which include communications, transmission and metering facilities owned by the Company to provide supervisory control and data acquisition, and automatic control for its customers.

      For base supply, the Company charges the distribution cooperative a demand charge, an energy charge and a fuel charge. The demand charge for each contract year is set forth in the agreement and is subject to increase for environmental legislation or occupational safety and health laws enacted after the effective date of the agreement. The Company can increase the demand charge to the extent its cost of providing supplemental supply exceeds $400/ MW. The energy charge is fixed through 2004, and decreased slightly for the remainder of the contract term. The fuel charge is a pass through of fuel and purchased energy costs. The distribution cooperative may elect to be charged based on a guaranteed coal fired heat rate of 10,600 Btu/kWh, and it may also select fixed fuel factors as set forth in the agreement for each year through 2008. The one distribution cooperative which selected this form of agreement elected to utilize the fixed fuel factors. For the years after 2008, the Company will offer additional fixed fuel factors for five-year periods that may be elected. For the

24

 
LOUISIANA GENERATING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

years after 2008, the distribution cooperative may also elect to have its charges computed under the pass through provisions with or without the guaranteed coal-fired heat rate.

      At the beginning of year six, the Company will establish a rate fund equal to the ratable share of $18 million. The amount of the fund will be approximately $720,000. This fund will be used to offset the energy costs of the Form B distribution cooperatives which elected the fuel pass through provision of the fuel charge, to the extent the cost of power exceeds $0.04/kWh. Any funds remaining at the end of the term of the power supply agreement will be returned to the Company.

 	Form C Agreements	
      Four distribution cooperatives selected the Form C power supply agreement. The Form C power supply agreement is identical to the Form A power supply agreement, except for the following.

      The term of the Form C power supply agreement was for four years following the closing date of the acquisition of the Cajun Facilities. In October 2003, the Louisiana Public Service Commission approved contract extensions for all four Form C distribution cooperatives for terms of an additional five or ten years.

      The Company will charge the distribution cooperative a demand rate, a variable operation and maintenance charge and a fuel charge. The Company will not offer the distribution cooperatives which select the Form C agreement any new incentive rates, but will continue to honor existing incentive rates. At the end of the term of the agreement, the distribution cooperative is obligated to purchase the specific delivery facilities for a purchase price equal to the depreciated book value.

 	Other Power Supply Agreements	
      The Company assumed Cajun Electric’s rights and obligations under two consecutive long-term power supply agreements with South Western Electric Power Company (“SWEPCO”), one agreement with South Mississippi Electric Power Association (“SMEPA”) and one agreement with Municipal Energy Agency of Mississippi (“MEAM”).

      The SWEPCO Operating Reserves and Off-Peak Power Sale Agreement terminates on December 31, 2007. The agreement requires the Company to supply 100 MW of off-peak energy during certain hours of the day to a maximum of 292,000 MWh per year and an additional 100 MW of operating reserve capacity and the associated energy within ten minutes of a phone request during certain hours to a maximum of 43,800 MWh of operating reserve energy per year. The obligation to purchase the 100 MW of off-peak energy is contingent on the Company’s ability to deliver operating reserve capacity and energy associated with operating reserve capacity. At the Company’s request it will supply up to 100 MW of nonfirm, on peak capacity and associated energy.

      The SWEPCO Operating Reserves Capacity and Energy Power Sale Agreement is effective January 1, 2008 through December 31, 2026. The agreement requires the Company to provide 50 MW of operating reserve capacity within 10 minutes of a phone request. In addition, SWEPCO is granted the right to purchase up to 21,900 MWh/year of operating reserve energy.

      The SMEPA Unit Power Sale Agreement is effective through May 31, 2009, unless terminated following certain regulatory changes, changes in fuel costs or destruction of the Cajun Facilities. The agreement requires the Company to provide 75 MW of capacity and the associated energy from Big Cajun II, Unit 1 and an option for SMEPA to purchase additional capacity and associated energy if the Company determines that it is available, in 10 MW increments, up to a total of 200 MW. SMEPA is required to schedule a minimum of 25 MW plus 37% of any additional capacity that is purchased. The capacity charge is fixed through May 31, 2004, and increases for the period June 1, 2004 through May 31, 2009, including transmission costs to the

25

 
LOUISIANA GENERATING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

delivery point and any escalation of expenses. The energy charge is 110% of the incremental fuel cost for Big Cajun II, Unit 1.

      The MEAM Power Sale Agreement is effective through May 31, 2010, with an option for MEAM to extend through September 30, 2015, upon five years advance notice. The agreement requires the Company to provide 20 MW of firm capacity and associated energy with an option for MEAM to increase the capacity purchased to a total of 30 MW upon five years advance notice. The capacity charge is fixed. The operation and maintenance charge is a fixed amount which escalates at 3.5% per year. There is a transmission charge which varies depending upon the delivery point. The price for energy associated with the firm capacity is 110% of the incremental generating cost to the Company and is adjusted to include transmission losses to the delivery point.

 	Coal Supply Agreement	
      The Company has a coal supply agreement with Triton Coal. The coal is primarily sourced from Triton Coal’s Buckskin and North Rochelle mines located in Powder River Basin, Wyoming. The coal supply agreement has an initial term ending March 31, 2005. The agreement is for the full coal requirements of Big Cajun II. The agreement establishes a base price per ton for coal supplied by Triton Coal. The base price is subject to adjustment for changes in the level of taxes or other government fees and charges, variations in the caloric value and sulfur content of the coal shipped, and changes in the price of SO(2) emission allowances. The base price is based on certain annual weighted average quality specifications, subject to suspension and rejection limits.

 	Coal Transportation Agreement	
      The Company entered into a coal transportation agreement with Burlington Northern and Santa Fe Railway and American Commercial Terminal. The term of the agreement is five years from March 31, 2000. This agreement provides for the transportation of all of the coal requirements of Big Cajun II from the mines in Wyoming to Big Cajun II.

 	Transmission and Interconnection Agreements	
      The Company assumed Cajun Electric’s existing transmission agreements with Central Louisiana Electric Company, SWEPCO; and Entergy Services, Inc., acting as agent for Entergy Arkansas, Inc., Entergy Gulf States, Inc., Entergy Louisiana, Inc., Entergy Mississippi, Inc., and Entergy New Orleans, Inc. The Company also entered into two interconnection and operating agreements with Entergy Gulf States, Inc. on May 1, 2002. The Cajun facilities are connected to the transmission system of Entergy Gulf States, Inc. and power is delivered to the distribution cooperatives at various delivery points on the transmission systems of Entergy Gulf States, Inc., Entergy Louisiana, Inc., Central Louisiana Electric Company and SWEPCO. The Company also assumed from Cajun Electric 20 interchange and sales agreements with utilities and cooperatives, providing access to a 12 state area.

 	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 United States. These laws and regulations generally require lengthy and complex processes to obtain licenses, permits and approvals from federal, state and local agencies. If such laws and regulations become more stringent and the Company’s facilities are not exempted from coverage, the Company could be required to make extensive modifications to further reduce potential environmental impacts. Also, the Company could be held responsible under environmental and safety laws for the cleanup of pollutant releases at its facilities or at off-site locations where it has sent wastes.

26

 
LOUISIANA GENERATING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

      The Company and its subsidiaries strive to exceed the standards of compliance with applicable environmental and safety regulations. Nonetheless, the Company expects that future liability under or compliance with environmental and safety requirements could have a material effect on its operations or competitive position. It is not possible at this time to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of possible changes to environmental and safety regulations, regulatory interpretations or enforcement policies. 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.

      The Company establishes accruals where reasonable estimates of probable environmental and safety liabilities are possible. The Company adjusts the accruals when new remediation responsibilities are discovered and probable costs become estimable, or when current remediation estimates are adjusted to reflect new information.

      Under various federal, state and local environmental laws and regulations, a current or previous owner or operator of any facility, including an electric generating 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, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended by the Superfund Amendments and Reauthorization Act of 1986, impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and courts have interpreted liability under such laws to be strict (without fault) and joint and several. The cost of investigation, remediation or removal of any hazardous or toxic substances or petroleum products could be substantial. The Company has not been named as a potentially responsible party with respect to any off-site waste disposal matter.

      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 the Company (one of the instruments allowed by the Louisiana Department of Environmental Quality for providing financial assurance for expenses associated with closure and post-closure care of the ponds). The value of the trust fund is approximately $4.8 million at December 31, 2003, and the Company is making annual payments to the fund in the amount of about $116,000. See Note 18.

      The Louisiana Department of Environmental Quality has promulgated State Implementation Plan revisions to bring the Baton Rouge ozone nonattainment area into compliance with National Ambient Air Quality Standards. The Company participated in development of the revisions, which require the reduction of NO(x) emissions at the gas-fired Big Cajun I Power Station and coal-fired Big Cajun II Power Station to 0.1 pounds NO(x) per million Btu heat input and 0.21 pounds NO(x) per million Btu heat input, respectively. This revision of the Louisiana air rules would appear to constitute a change-in-law covered by agreement between the Company and the electric cooperatives allowing the costs of added combustion controls to be passed through to the cooperatives. The capital cost of combustion controls required at the Big Cajun II Generating Station to meet the state’s NOx regulations will total about $10.0 million each for Units 1 & 2. Unit 3 has already made such changes. The capital cost of combustion controls required at the Big Cajun I Generating Station to meet the state’s NO(x) regulations will total about $5 million to $10 million for the Unit 1 & 2 steam boilers.

27

 
LOUISIANA GENERATING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

 	Legal Issues	

 	United States Environmental Protection Agency Request for Information under Section 114 of the Clean Air Act	
      On January 27, 2004, Louisiana Generating, LLC and Big Cajun II received a request for information under Section 114 of the Clean Air Act from the United States Environmental Protection Agency (“EPA”) seeking information primarily relating to physical changes made at Big Cajun II in 1994 and 1995 by the predecessor owner of that facility. Louisiana Generating, LLC and Big Cajun II have been responding to the EPA request in an appropriate manner. At the present time, the Company cannot predict the probable outcome in this matter.

      Two lawsuits are pending in Federal Court involving 39 former employees of Cajun Electric Power Cooperative, Inc. who claim age/race/sex discrimination in failure to hire by the Company. One lawsuit was dismissed on summary judgment and has been appealed. In the remaining lawsuit, we are awaiting the District Court’s ruling on the Company’s motions for summary judgment.

 	In the Matter of Louisiana Generating, LLC, Adversary Proceeding No. 2002-1095 1-EQ on the Docket of the Louisiana Division of Administrative Law	
      During 2000, the Louisiana Department of Environmental Quality (“DEQ”) issued a Part 70 Air Permit modification to the Company to construct and operate two 240 MW natural gas-fired turbines. The Part 70 Air Permit set emissions limits for the criteria air pollutants, including NOx, based on the application of Best Available Control Technology (“BACT”). The BACT limitation for NO(x) was based on the guarantees of the manufacturer, Siemens-Westinghouse. The Company sought an interim emissions limit to allow Siemens-Westinghouse time to install additional control equipment. To establish the interim limit, DEQ issued a Compliance Order and Notice of Potential Penalty, No. AE-CN-02-0022, on September 8, 2002, which is, in part, subject to the referenced administrative hearing. DEQ alleged that Louisiana Generating did not meet its NO(x) emissions limit on certain days, did not conduct all opacity monitoring and did not complete all record keeping and certification requirements. The Company intends to vigorously defend certain claims and any future penalty assessment, while also seeking an amendment of its limit for NO(x). An amended permit application and an amended BACT analysis were submitted to DEQ on February 27, 2004. DEQ is presently reviewing the amended application. In addition, NRG Energy may assert breach of warranty claims against the manufacturer. With respect to the administrative action described above, at this time the Company is unable to predict the eventual outcome of this matter or the potential loss contingencies, if any, to which the Company may be subject.

16.	Regulatory Issues	
      The Company’s assets are located within the control areas of the local, regulated, and sometimes vertically integrated, utilities, primarily Entergy Corporation (“Entergy”). The utility performs the scheduling, reserve and reliability functions that are administered by the Independent System Operator (“ISO”) ISOs in certain other regions of the United States and Canada. The Company operates a National Electric Reliability Council (“NERC”) certified control area within the Entergy control area, which is comprised of the Company’s generating assets and its co-op customer loads. Although the reliability functions performed are essentially the same, the primary differences between these markets lie principally in the physical delivery and price discovery mechanisms. In the South Central region, all power sales and purchases are consummated bilaterally between individual counter-parties, and physically delivered either within or across the physical control areas of the transmission owners from the source generator to the sink load. Transacting counter-parties are required to reserve and purchase transmission services from the intervening transmission owners at their Federal Energy Regulatory Commission (“FERC”) approved tariff rates. Included with these transmission services are the reserve and ancillary costs. Energy prices in the South Central region are determining and

28

 
LOUISIANA GENERATING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

agreed to in bilateral negotiations between representatives of the transacting counter-parties, using market information gleaned by the individual marketing agents arranging the transactions.

      In the South Central area, including Entergy’s service territory, the present energy market is not a centralized market and does not have an independent system operator as is found in the Northeast markets. The Company presently has long-term all requirements contracts with 11 Louisiana Distribution Cooperatives, and long-term contracts with the Municipal Energy Agency of Mississippi, South Mississippi Electric Power Association and Southwestern Electric Power Company. The Distribution Cooperatives serve approximately 300,000 to 350,000 retail customers.

      On March 31, 2004, Entergy filed with FERC a proposal: to have an independent person monitor the Entergy operation of the transmission system, to review the pricing structure for transmission expansion and to establish a weekly procurement process by which Entergy and other load serving entities could purchase energy. On June 30, 2004, the Company intervened in the case and requested FERC reject the proposal. FERC has not ruled on this request. Also, it is unclear at this time how these recent developments will impact the Company.

17.	Jointly Owned Plant	
      On March 31, 2000, the Company acquired a 58% interest in the Big Cajun II, Unit 3 generation plant. Entergy Gulf States, Inc. owns the remaining 42%. Big Cajun II, Unit 3 is operated and maintained by the Company pursuant to a joint ownership participation and operating agreement. Under this agreement, the Company and Entergy Gulf States, Inc. are each entitled to their ownership percentage of the hourly net electrical output of Big Cajun II, Unit 3. All fixed costs are shared in proportion to the ownership interests. Fixed costs include the cost of operating common facilities. All variable costs are borne in proportion to the energy delivered to the owners. The Company’s statements of operations include the Company’s share of all fixed and variable costs of operating the unit.

      The Company’s 58% share of the property, plant and equipment and construction in progress as revalued to fair value upon the application of push down accounting at December 31, 2003 and December 6, 2003, was $183.2 million and $183.2 million, and corresponding accumulated depreciation and amortization was $0.5 million and $0, respectively. The Company’s 58% share of the original cost was $189.0 million and is included in property, plant and equipment and construction in progress at December 31, 2002, the corresponding accumulated depreciation and amortization was $12.3 million.

18.	Decommissioning Fund	
      The Company is required by the State of Louisiana Department of Environmental Quality to rehabilitate its Big Cajun II ash and wastewater impoundment areas upon removal from service of the Big Cajun II facilities. On July 1, 1989, a guarantor trust fund (the “Solid Waste Disposal Trust Fund”) was established to accumulate the estimated funds necessary for such purpose. The Company’s predecessor deposited $1.06 million in the Solid Waste Disposal Trust Fund in 1989, and funded $116,000 annually thereafter, based upon an estimated future rehabilitation cost (in 1989 dollars) of approximately $3.5 million and the remaining estimated useful life of the Big Cajun II facilities. Prior to January 1, 2003, cumulative contributions to the Solid Waste Disposal Trust Fund and earnings on the investments therein were accrued as a decommissioning liability. Effective January 1, 2003, the Company adopted SFAS No. 143 and accounts for its decommissioning liability in accordance with that standard. At December 31, 2003, December 6, 2003 and December 31, 2002, the carrying value of the trust fund investments and the related accrued decommissioning liability was approximately $4.8 million, $4.8 million and $4.6 million, respectively. The trust fund investments are comprised of various debt securities of the United States and are carried at amortized cost, which approximates their fair value.

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LOUISIANA GENERATING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

19.	Guarantees	
      In November 2002, the FASB issued FIN No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others . The initial recognition and initial measurement provisions of this interpretation were applicable on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor’s fiscal year end. The disclosure requirements became effective for financial statements of interim or annual periods ending after December 15, 2002. The interpretation addresses the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees. The interpretation also clarifies the requirements related to the recognition of a liability by a guarantor at the inception of the guarantee for the obligations the guarantor has undertaken in issuing the guarantee.

      In connection with push down accounting, all outstanding guarantees were considered new; accordingly, the Company applied the provisions of FIN 45 to all of those guarantees. Each guarantee was reviewed for the requirement to recognize a liability at inception.

      The Company was a guarantor of the bonds issued on March 30, 2000 to acquire the Cajun Facilities. On December 23, 2003, South Central paid in full the remaining balance of such bonds.

      In addition, the Company is a guarantor under the debt issued by the Company’s ultimate parent, NRG Energy. NRG Energy issued $1.25 billion of 8% Second Priority Notes on December 23, 2003, due and payable on December 15, 2013. On January 28, 2004, NRG Energy also issued $475.0 million of Second Priority Notes, under the same terms and indenture as its December 23, 2003 offering.

      NRG Energy’s payment obligations under the notes and all related Parity Lien Obligations are guaranteed on an unconditional basis by each of NRG Energy’s current and future restricted subsidiaries, of which the Company is one. The notes are jointly and severally guaranteed by each of the guarantors. The subsidiary guarantees of the notes are secured, on a second priority basis, equally and ratably with any future Parity Lien Debt, by security interest in all of the assets of the guarantors, except certain excluded assets, subject to liens securing parity lien debt and other permitted prior liens.

      The Company’s obligations pursuant to its guarantees of the performance, equity and indebtedness obligations were as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantee/	 	 	 	 	 	 	
 	 	Maximum	 	 	 	Expiration	 	 	
 	 	Exposure	 	Nature of Guarantee	 	Date	 	Triggering Event	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Project/Subsidiary	 	 	 	 	 	 	 	 	 	 	 	 	
NRG Energy Second Priority Notes due 2013	 	$	1,753,000	 	 	Obligations under credit agreement	 	 	2013	 	 	Nonperformance	

20.	Income Taxes (Restatement)	
      The Company is included in the consolidated tax return filings as a wholly owned indirect subsidiary of NRG Energy. Reflected in the financial statements and notes below are separate company federal and state tax provisions as if the Company had prepared separate filings. An income tax provision has been established on the accompanying financial statements as of the earliest period presented in order to reflect income taxes as if the Company filed its own tax return. The Company’s ultimate parent, NRG Energy, does not have a tax allocation agreement with its subsidiaries and prior to January 1, 2003, income taxes were not recorded or allocated to non tax paying entities or entities such as the Company which are treated as disregarded entities for tax purposes. Accordingly, the previously issued financial statements for the years ended December 31, 2002 and 2001, have been restated to include the effects of recording an income tax provision. Because the

30

 
LOUISIANA GENERATING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

Company is not a party to a tax sharing agreement, current tax expense (benefit) is recorded as a capital contribution from (distribution to) the Company’s parent. The cumulative effect of recording an income tax provision (benefit) and deferred taxes resulted in recording as of December 31, 2000, a net deferred tax liability of $20.4 million and a reduction to member’s equity of $20.4 million.

      The provision (benefit) for income taxes consists of the following:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Current	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Federal	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	
 	State	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Deferred	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Federal	 	 	250	 	 	 	(7,029	)	 	 	6,958	 	 	 	7,016	 	
 	State	 	 	62	 	 	 	(1,747	)	 	 	1,729	 	 	 	1,743	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	312	 	 	 	(8,776	)	 	 	8,687	 	 	 	8,759	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Total income tax expense (benefit)	 	$	312	 	 	$	(8,776	)	 	$	8,687	 	 	$	8,759	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Effective tax rate	 	 	40.6	%	 	 	10.0	%	 	 	68.6	%	 	 	40.1  	%	
      The pre-tax income (loss) was as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
U.S. 	 	$	768	 	 	$	(22,025	)	 	$	12,664	 	 	$	21,879	 	
31

 
LOUISIANA GENERATING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

      The components of the net deferred income tax (assets) liabilities were:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Deferred tax liabilities	 	 	 	 	 	 	 	 	 	 	 	 	
 	Property	 	$	32,769	 	 	$	31,667	 	 	$	52,579	 	
 	Emissions credits	 	 	37,810	 	 	 	37,810	 	 	 	—	 	
 	Development costs	 	 	—	 	 	 	—	 	 	 	3,358	 	
 	Other	 	 	99	 	 	 	93	 	 	 	1,737	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total deferred tax liabilities	 	 	70,678	 	 	 	69,570	 	 	 	57,674	 	
Deferred tax assets	 	 	 	 	 	 	 	 	 	 	 	 	
 	Deferred compensation, accrued vacation and other reserves	 	 	3,371	 	 	 	3,357	 	 	 	916	 	
 	Development costs	 	 	5,660	 	 	 	5,821	 	 	 	—	 	
 	Difference between book and tax basis out-of-market contracts	 	 	148,892	 	 	 	149,776	 	 	 	—	 	
 	Domestic tax loss carryforwards	 	 	41,194	 	 	 	39,538	 	 	 	18,947	 	
 	Asset retirement obligation	 	 	829	 	 	 	825	 	 	 	—	 	
 	Other	 	 	1,902	 	 	 	1,735	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total deferred tax assets (before valuation allowance)	 	 	201,848	 	 	 	201,052	 	 	 	19,863	 	
Valuation allowance	 	 	(131,170	)	 	 	(131,482	)	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
Net deferred tax assets	 	 	70,678	 	 	 	69,570	 	 	 	19,863	 	

	 	 	 	

	 	 	 	

	 	
Net deferred tax liabilities	 	$	—	 	 	$	—	 	 	$	37,811	 	

	 	 	 	

	 	 	 	

	 	
      The net deferred tax (assets) liabilities consists of:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2003	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Current deferred tax assets	 	$	—	 	 	$	—	 	 	$	(85	)	
Noncurrent deferred tax liabilities	 	 	—	 	 	 	—	 	 	 	37,896	 	

	 	 	 	

	 	 	 	

	 	
Net deferred tax liabilities	 	$	—	 	 	$	—	 	 	$	37,811	 	

	 	 	 	

	 	 	 	

	 	
32

 
LOUISIANA GENERATING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

      The effective income tax rates of continuing operations differ from the statutory federal income tax rate of 35% as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	 	 	 	 	
 	 	Company	 	 	 	Predecessor Company	 	 	

	 	 	 	

	 	 	
 	 	For the	 	 	 	For the	 	 	 	 	
 	 	Period from	 	 	 	Period from	 	 	 	 	 	 	
 	 	December 6,	 	 	 	January 1,	 	 	 	For the Years Ended	 	 	
 	 	2003 to	 	 	 	2003 to	 	 	 	December 31,	 	 	
 	 	December 31,	 	 	 	December 5,	 	 	 	

	 	 	
 	 	2003	 	 	 	2003	 	 	 	2002	 	 	 	2001	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	
 	 	 	
 	 	(In thousands of dollars)	
Income (loss) before taxes	 	$	768	 	 	 	 	 	 	$	(22,025	)	 	 	 	 	 	$	12,664	 	 	 	 	 	 	$	21,879	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	
Tax at 35%	 	 	269	 	 	 	35.0%	 	 	 	(7,709	)	 	 	35.0	%	 	 	4,432	 	 	 	35.0%	 	 	 	7,658	 	 	 	35.0%	 	
State taxes (net of federal benefit)	 	 	40	 	 	 	5.2%	 	 	 	(1,135	)	 	 	5.2	%	 	 	1,124	 	 	 	8.9%	 	 	 	1,133	 	 	 	5.2%	 	
Valuation allowance	 	 	—	 	 	 	0.0%	 	 	 	—	 	 	 	0.0	%	 	 	—	 	 	 	0.0%	 	 	 	—	 	 	 	0.0%	 	
Other	 	 	3	 	 	 	0.4%	 	 	 	68	 	 	 	(0.3	)%	 	 	3,131	 	 	 	24.7%	 	 	 	(32	)	 	 	(0.1)%	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	
Income tax expense (benefit)	 	$	312	 	 	 	40.6%	 	 	$	(8,776	)	 	 	39.9	%	 	$	8,687	 	 	 	68.6%	 	 	$	8,759	 	 	 	40.1%	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	

21.	Reorganization Cash Payments and Receipts	

 	Cash Receipts	
      During the period from May 14, 2003 to December 5, 2003, the Company received $0.8 million of interest income on cash balances. No such amounts were received during the period from December 6, 2003 to December 31, 2003.

 	Cash Payments	

 	Professional Fees	
      During the period from May 14, 2003 to December 5, 2003 and the period from December 6, 2003 to December 31, 2003, the Company made cash payments for professional fees to financial and legal advisors of $0.6 million and $0.1 million, respectively.

 	Refinancing Activities	
      The Company made cash payments of $750.8 million related to the repayment of debt, including accrued interest of $15.3 million upon the emergence from bankruptcy on December 23, 2003, with proceeds from NRG Energy’s recently completed corporate level refinancing. The Company also made cash payments of $11.3 million for a pre-payment settlement upon the early payment of the debt.

 	Creditor Payments	
      Upon the Company’s emergence from bankruptcy, no cash payments were made to creditors during the period from December 6, 2003 to December 31, 2003.

33

 

REPORT OF INDEPENDENT AUDITORS ON
FINANCIAL STATEMENT SCHEDULE

To the Member of
Louisiana Generating LLC:

      Our audits of the financial statements referred to in our report dated March 10, 2004, also included an audit of the financial statement schedule listed herein. In our opinion, this financial statement schedule for the period from January 1, 2003 to December 5, 2003 and for the two years ended December 31, 2002, presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements.
 	 	
 	/s/ PricewaterhouseCoopers LLP	

	
 	PricewaterhouseCoopers LLP	
Minneapolis, Minnesota
March 10, 2004

34

 

REPORT OF INDEPENDENT AUDITORS ON
FINANCIAL STATEMENT SCHEDULE

To the Member of
Louisiana Generating LLC:

      Our audits of the financial statements referred to in our report dated March 10, 2004, also included an audit of the financial statement schedule listed herein. In our opinion, this financial statement schedule for the period from December 6, 2003 to December 31, 2003 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements.
 	 	
 	/s/ PricewaterhouseCoopers LLP	

	
 	PricewaterhouseCoopers LLP	
Minneapolis, Minnesota
March 10, 2004

35

 

LOUISIANA GENERATING LLC

SCHEDULE II. VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2003, 2002 and 2001

 	 	 	 	Additions	 	 	 	 	

	 	 	 	 	
 	 	Balance at	 	Charged to	 	 	 	 	 	Balance at	
 	 	Beginning of	 	Costs and	 	Charged to	 	 	 	End of	
Description	 	Period	 	Expenses	 	Other	 	Deductions	 	Period	

	 	

	 	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands)	
Income tax valuation allowance, deducted from deferred tax assets in the balance sheet:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Predecessor Company	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Year ended December 31, 2001	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	
Year ended December 31, 2002	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
January 1 - December 5, 2003	 	 	—	 	 	 	131,482	 	 	 	—	 	 	 	—	 	 	 	131,482	 	

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reorganized Company	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
December 6 - December 31, 2003	 	 	131,482	 	 	 	—	 	 	 	—	 	 	 	312	 	 	 	131,170	 	
36

 

EXHIBIT 99.3

NRG NORTHEAST GENERATING LLC

CONSOLIDATED FINANCIAL STATEMENTS

At December 31, 2003, December 6, 2003 and
December 31, 2002, and for the Period from
December 6, 2003 to December 31, 2003, the Period
from January 1, 2003 to December 5, 2003 and for
the Years Ended December 31, 2002 and 2001

 

NRG NORTHEAST GENERATING LLC

INDEX
 	 	 	 	 	
 	 	Page(s)	

	
Reports of Independent Auditors	 	 	2-3	 	
Consolidated Financial Statements	 	 	 	 	
Consolidated Balance Sheets at December 31, 2003, December 6, 2003 and December 31, 2002	 	 	4	 	
Consolidated Statements of Operations for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001	 	 	5	 	
Consolidated Statements of Members’ Equity for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001	 	 	6	 	
Consolidated Statements of Cash Flows for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001	 	 	7	 	
Notes to Consolidated Financial Statements	 	 	8-36	 	
Reports of Independent Auditors on Financial Statement Schedule	 	 	37-38	 	
Financial Statement Schedule	 	 	39	 	
1

 

REPORT OF INDEPENDENT AUDITORS

To the Members of
NRG Northeast Generating LLC

      In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, of members’ equity and of cash flows present fairly, in all material respects, the financial position of NRG Northeast Generating LLC (“Predecessor Company”) and its subsidiaries at December 31, 2002, and the results of their operations and their cash flows for the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      As discussed in Note 1 to the consolidated financial statements, on May 14, 2003, NRG Energy, Inc. and certain of its subsidiaries, including the Company, filed a petition with the United States Bankruptcy Court for the Southern District of New York for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. NRG Energy, Inc.’s Plan of Reorganization was substantially consummated on December 5, 2003, and Reorganized NRG emerged from bankruptcy. The Company emerged from bankruptcy on December 23, 2003, pursuant to a separate plan of reorganization referred to as the Northeast/South Central Plan of Reorganization. The impact of NRG Energy, Inc.’s emergence from bankruptcy and fresh start accounting was applied to the Company on December 5, 2003 under push down accounting methodology.

      As discussed in Note 16 to the consolidated financial statements, the Company has restated its previously issued consolidated financial statements for the years ended December 31, 2002 and 2001 to reflect an income tax provision (benefit) and deferred taxes.
 	 	
 	/s/ PRICEWATERHOUSECOOPERS LLP	

	
 	PricewaterhouseCoopers LLP	
Minneapolis, Minnesota
March 10, 2004

2

 

REPORT OF INDEPENDENT AUDITORS

To the Members of
NRG Northeast Generating LLC

      In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of members’ equity and of cash flows present fairly, in all material respects, the financial position of NRG Northeast Generating LLC (“Reorganized Company”) and its subsidiaries at December 31, 2003 and December 6, 2003, and the results of their operations and their cash flows for the period from December 6, 2003 to December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      As discussed in Note 1 to the consolidated financial statements, on May 14, 2003, NRG Energy, Inc. and certain of its subsidiaries, including the Company, filed a petition with the United States Bankruptcy Court for the Southern District of New York for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. NRG Energy, Inc.’s Plan of Reorganization was substantially consummated on December 5, 2003, and Reorganized NRG emerged from bankruptcy. The Company emerged from bankruptcy on December 23, 2003, pursuant to a separate plan of reorganization referred to as the Northeast/ South Central Plan of Reorganization. The impact of NRG Energy, Inc.’s emergence from bankruptcy and fresh start accounting was applied to the Company on December 5, 2003 under push down accounting methodology.
 	 	
 	/s/ PRICEWATERHOUSECOOPERS LLP	

	
 	PricewaterhouseCoopers LLP	
Minneapolis, Minnesota
March 10, 2004

3

 

NRG NORTHEAST GENERATING LLC

CONSOLIDATED BALANCE SHEETS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	 	 	 	(As Restated)	
 	 	 	
 	 	(In thousands of dollars)	
ASSETS	
Current assets	 	 	 	 	 	 	 	 	 	 	 	 	
 	Cash and cash equivalents	 	$	6,250	 	 	$	5,258	 	 	$	14,354	 	
 	Restricted cash	 	 	4,198	 	 	 	3,608	 	 	 	—	 	
 	Accounts receivable, net of allowance for doubtful accounts of $0, $0 and $50,712, respectively	 	 	306	 	 	 	306	 	 	 	118,153	 	
 	Accounts receivable — affiliates	 	 	9,665	 	 	 	24,349	 	 	 	—	 	
 	Inventory	 	 	107,441	 	 	 	108,674	 	 	 	123,963	 	
 	Derivative instruments valuation	 	 	611	 	 	 	—	 	 	 	23,039	 	
 	Prepayments and other current assets	 	 	33,812	 	 	 	29,426	 	 	 	38,309	 	
 	Current deferred income tax	 	 	—	 	 	 	—	 	 	 	9,709	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total current assets	 	 	162,283	 	 	 	171,621	 	 	 	327,527	 	
Property, plant and equipment, net of accumulated depreciation of $2,911, $0 and $157,534, respectively	 	 	843,832	 	 	 	845,872	 	 	 	1,333,928	 	
Debt issuance costs, net of accumulated amortization of $0, $0, and $1,161, respectively	 	 	—	 	 	 	—	 	 	 	8,995	 	
Derivative instruments valuation	 	 	—	 	 	 	—	 	 	 	9,601	 	
Intangible assets, net of accumulated amortization of $523, $0 and $2,605, respectively	 	 	213,687	 	 	 	214,210	 	 	 	23,395	 	
Deferred income tax	 	 	91,565	 	 	 	91,874	 	 	 	—	 	
Other assets	 	 	7,355	 	 	 	7,355	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total assets	 	$	1,318,722	 	 	$	1,330,932	 	 	$	1,703,446	 	

	 	 	 	

	 	 	 	

	 	
 	
LIABILITIES AND MEMBERS’ EQUITY	
Current liabilities	 	 	 	 	 	 	 	 	 	 	 	 	
 	Current portion of long-term debt	 	$	—	 	 	$	556,500	 	 	$	556,500	 	
 	Note payable — affiliate	 	 	30,000	 	 	 	30,000	 	 	 	30,000	 	
 	Accounts payable	 	 	177	 	 	 	64	 	 	 	14,607	 	
 	Accounts payable — affiliates	 	 	—	 	 	 	—	 	 	 	11,476	 	
 	Accrued interest	 	 	2,557	 	 	 	26,342	 	 	 	4,198	 	
 	Other accrued liabilities	 	 	51,225	 	 	 	59,344	 	 	 	48,881	 	
 	Current deferred income tax	 	 	453	 	 	 	442	 	 	 	—	 	
 	Derivative instruments valuation	 	 	190	 	 	 	95	 	 	 	13,017	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total current liabilities	 	 	84,602	 	 	 	672,787	 	 	 	678,679	 	
Derivative instruments valuation	 	 	—	 	 	 	—	 	 	 	7,559	 	
Noncurrent deferred income tax	 	 	—	 	 	 	—	 	 	 	68,106	 	
Other long-term obligations	 	 	7,528	 	 	 	7,493	 	 	 	27,936	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total liabilities	 	 	92,130	 	 	 	680,280	 	 	 	782,280	 	

	 	 	 	

	 	 	 	

	 	
Commitments and contingencies	 	 	 	 	 	 	 	 	 	 	 	 	
Members’ equity	 	 	1,226,592	 	 	 	650,652	 	 	 	921,166	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total liabilities and members’ equity	 	$	1,318,722	 	 	$	1,330,932	 	 	$	1,703,446	 	

	 	 	 	

	 	 	 	

	 	
The accompanying notes are an integral part of these consolidated financial statements.

4

 

NRG NORTHEAST GENERATING LLC

CONSOLIDATED STATEMENTS OF OPERATIONS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	 	 	 	(As Restated)	 	(As Restated)	
 	 	 	
 	 	(In thousands of dollars)	
Revenues	 	$	60,471	 	 	$	730,463	 	 	$	693,869	 	 	$	1,050,688	 	
Operating costs	 	 	40,360	 	 	 	597,752	 	 	 	494,446	 	 	 	712,148	 	
Depreciation	 	 	2,911	 	 	 	61,271	 	 	 	54,227	 	 	 	48,900	 	
General and administrative expenses	 	 	4,205	 	 	 	40,927	 	 	 	44,262	 	 	 	24,372	 	
Reorganization items	 	 	241	 	 	 	5,148	 	 	 	—	 	 	 	—	 	
Restructuring and impairment charges	 	 	—	 	 	 	230,571	 	 	 	50,524	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	Income (loss) from operations	 	 	12,754	 	 	 	(205,206	)	 	 	50,410	 	 	 	265,268	 	
Other (expense) income, net	 	 	(345	)	 	 	441	 	 	 	5,273	 	 	 	4,624	 	
Interest expense	 	 	(2,103	)	 	 	(50,746	)	 	 	(51,798	)	 	 	(58,637	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	Income (loss) before income taxes	 	 	10,306	 	 	 	(255,511	)	 	 	3,885	 	 	 	211,255	 	
Income tax expense (benefit)	 	 	4,460	 	 	 	(109,824	)	 	 	3,460	 	 	 	91,451	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	Net income (loss)	 	$	5,846	 	 	$	(145,687	)	 	$	425	 	 	$	119,804	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
The accompanying notes are an integral part of these consolidated financial statements.

5

 

NRG NORTHEAST GENERATING LLC

CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	Accumulated	 	 	
 	 	Members’	 	Members’	 	Accumulated	 	Other	 	Total	

	 	Contributions/	 	Net Income	 	Comprehensive	 	Members’	
 	 	Units	 	Amount	 	Distributions	 	(Loss)	 	Income	 	Equity	

	 	

	 	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Balances at December 31, 2000 (Predecessor Company) (As Restated)	 	 	1,000	 	 	$	1	 	 	$	724,036	 	 	$	—	 	 	$	—	 	 	$	724,037	 	
Cumulative effect upon adoption of SFAS No. 133	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	14,100	 	 	 	14,100	 	
Impact of SFAS No. 133 for the year ending December 31, 2001	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	93,641	 	 	 	93,641	 	
Net income	 	 	—	 	 	 	—	 	 	 	—	 	 	 	119,804	 	 	 	—	 	 	 	119,804	 	

	 	
Comprehensive income	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	227,545	 	
Contribution from members	 	 	—	 	 	 	—	 	 	 	83,861	 	 	 	—	 	 	 	—	 	 	 	83,861	 	
Distribution to members	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(52,727	)	 	 	—	 	 	 	(52,727	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Balances at December 31, 2001 (Predecessor Company) (As Restated)	 	 	1,000	 	 	 	1	 	 	 	807,897	 	 	 	67,077	 	 	 	107,741	 	 	 	982,716	 	
Impact of SFAS No. 133 for the year ending December 31, 2002	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(78,906	)	 	 	(78,906	)	
Net income	 	 	—	 	 	 	—	 	 	 	—	 	 	 	425	 	 	 	—	 	 	 	425	 	

	 	
Comprehensive loss	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(78,481	)	
Contribution from members	 	 	—	 	 	 	—	 	 	 	16,931	 	 	 	—	 	 	 	—	 	 	 	16,931	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Balances at December 31, 2002 (Predecessor Company) (As Restated)	 	 	1,000	 	 	 	1	 	 	 	824,828	 	 	 	67,502	 	 	 	28,835	 	 	 	921,166	 	
Impact of SFAS No. 133 for the period ending December 5, 2003	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(28,835	)	 	 	(28,835	)	
Net loss	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(145,687	)	 	 	—	 	 	 	(145,687	)	

	 	
Comprehensive loss	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(174,522	)	
Contribution from members	 	 	—	 	 	 	—	 	 	 	15,945	 	 	 	—	 	 	 	—	 	 	 	15,945	 	
Distribution to members	 	 	—	 	 	 	—	 	 	 	(91,783	)	 	 	—	 	 	 	—	 	 	 	(91,783	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Balances at December 5, 2003 (Predecessor Company)	 	 	1,000	 	 	 	1	 	 	 	748,990	 	 	 	(78,185	)	 	 	—	 	 	 	670,806	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Push down accounting adjustments	 	 	—	 	 	 	—	 	 	 	(98,339	)	 	 	78,185	 	 	 	—	 	 	 	(20,154	)	
Balances at December 6, 2003 (Reorganized Company)	 	 	1,000	 	 	 	1	 	 	 	650,651	 	 	 	—	 	 	 	—	 	 	 	650,652	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Contribution from members	 	 	—	 	 	 	—	 	 	 	570,094	 	 	 	—	 	 	 	—	 	 	 	570,094	 	
Net income and comprehensive income	 	 	—	 	 	 	—	 	 	 	—	 	 	 	5,846	 	 	 	—	 	 	 	5,846	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Balances at December 31, 2003 (Reorganized Company)	 	 	1,000	 	 	$	1	 	 	$	1,220,745	 	 	$	5,846	 	 	$	—	 	 	$	1,226,592	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
The accompanying notes are an integral part of these consolidated financial statements.

6

 

NRG NORTHEAST GENERATING LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	 	 	 	(As Restated)	 	(As Restated)	
 	 	 	
 	 	(In thousands of dollars)	
Cash flows from operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	$	5,846	 	 	$	(145,687	)	 	$	425	 	 	$	119,804	 	
Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Depreciation	 	 	2,911	 	 	 	61,271	 	 	 	54,227	 	 	 	48,900	 	
 	Amortization of debt issuance costs	 	 	—	 	 	 	5,646	 	 	 	411	 	 	 	409	 	
 	Amortization of intangible assets	 	 	523	 	 	 	2,172	 	 	 	—	 	 	 	—	 	
 	Deferred income taxes	 	 	320	 	 	 	(125,769	)	 	 	(13,471	)	 	 	7,590	 	
 	Current tax expense — noncash contribution from members	 	 	4,140	 	 	 	15,945	 	 	 	16,931	 	 	 	83,861	 	
 	Asset impairment	 	 	—	 	 	 	230,571	 	 	 	49,289	 	 	 	—	 	
 	Unrealized (gains) losses on derivatives	 	 	(516	)	 	 	(16,676	)	 	 	(14,457	)	 	 	31,227	 	
 	Allowance for doubtful accounts	 	 	—	 	 	 	—	 	 	 	50,712	 	 	 	(8,165	)	
 	Loss on disposal of assets	 	 	350	 	 	 	1,514	 	 	 	—	 	 	 	—	 	
 	Changes in assets and liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Accounts receivable	 	 	—	 	 	 	117,841	 	 	 	(112,840	)	 	 	109,800	 	
 	 	Accounts receivable/payable — affiliates	 	 	14,684	 	 	 	(35,825	)	 	 	11,476	 	 	 	(146,894	)	
 	 	Inventories	 	 	1,233	 	 	 	(7,977	)	 	 	48,252	 	 	 	(64,356	)	
 	 	Prepayments and other current assets	 	 	(4,386	)	 	 	8,883	 	 	 	(18,193	)	 	 	581	 	
 	 	Accounts payable	 	 	103	 	 	 	(14,543	)	 	 	12,057	 	 	 	(1,364	)	
 	 	Accrued interest	 	 	(23,785	)	 	 	22,144	 	 	 	2,038	 	 	 	(391	)	
 	 	Other accrued liabilities	 	 	(8,109	)	 	 	15,468	 	 	 	(19,396	)	 	 	(19,716	)	
 	 	Changes in other assets and liabilities	 	 	35	 	 	 	(27,359	)	 	 	4,149	 	 	 	4,705	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	Net cash (used in) provided by operating activities	 	 	(6,651	)	 	 	107,619	 	 	 	71,610	 	 	 	165,991	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Cash flows from investing activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Increase in restricted cash	 	 	(590	)	 	 	(3,608	)	 	 	—	 	 	 	—	 	
Capital expenditures	 	 	(1,221	)	 	 	(14,692	)	 	 	(34,126	)	 	 	(25,140	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	Net cash used in investing activities	 	 	(1,811	)	 	 	(18,300	)	 	 	(34,126	)	 	 	(25,140	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Cash flows from financing activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Proceeds from debt issuance — affiliate	 	 	—	 	 	 	—	 	 	 	30,000	 	 	 	—	 	
Contribution from members	 	 	565,954	 	 	 	—	 	 	 	—	 	 	 	—	 	
Distribution to members	 	 	—	 	 	 	(91,783	)	 	 	—	 	 	 	(52,727	)	
Principal payments on long-term debt	 	 	(556,500	)	 	 	—	 	 	 	(53,500	)	 	 	(90,000	)	
Debt issuance costs	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(198	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	Net cash provided by (used in) financing activities	 	 	9,454	 	 	 	(91,783	)	 	 	(23,500	)	 	 	(142,925	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	Net change in cash and cash equivalents	 	 	992	 	 	 	(2,464	)	 	 	13,984	 	 	 	(2,074	)	
Cash and cash equivalents	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Beginning of period	 	 	5,258	 	 	 	14,354	 	 	 	370	 	 	 	2,444	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
End of period	 	$	6,250	 	 	$	11,890	 	 	$	14,354	 	 	$	370	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Supplemental disclosures of cash flow information	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Interest paid (net of amount capitalized)	 	$	25,888	 	 	$	24,786	 	 	$	49,760	 	 	$	58,541	 	
Noncash contribution from members for current tax expense	 	 	4,140	 	 	 	15,945	 	 	 	16,931	 	 	 	83,861	 	
The accompanying notes are an integral part of these consolidated financial statements.

7

 

NRG NORTHEAST GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.	Organization	
      NRG Northeast Generating LLC (the “Company” or “NRG Northeast”), a wholly owned indirect subsidiary of NRG Energy, Inc. (“NRG Energy”), owns electric power generation plants in the northeastern region of the United States. The Company’s members are Northeast Generation Holding LLC and NRG Eastern LLC, each of which owns a 50% interest in the Company and are directly held wholly owned subsidiaries of NRG Energy. The Company was formed in 1999 for the purpose of financing, acquiring, owning, operating and maintaining, through its subsidiaries and affiliates the power generation facilities owned by Arthur Kill Power LLC, Astoria Gas Turbine Power LLC, Connecticut Jet Power LLC, Devon Power LLC, Dunkirk Power LLC, Huntley Power LLC, Middletown Power LLC, Montville Power LLC, Norwalk Power LLC, Oswego Harbor Power LLC and Somerset Power LLC.

 	Recent Developments	
      On May 14, 2003, NRG Energy and 25 of its direct and indirect wholly owned subsidiaries commenced voluntary petitions under Chapter 11 of the bankruptcy code in the United States Bankruptcy Court for the Southern District of New York. The Company and its direct subsidiaries were included in the Chapter 11 filing. During the bankruptcy proceedings, NRG Energy continued to conduct business and manage the companies as debtors in possession pursuant to sections 1107(a) and 1108 of the bankruptcy code. Two plans of reorganization were filed in connection with the restructuring efforts. The first, filed on May 14, 2003, and referred to as NRG Energy’s Plan of Reorganization, relates to NRG Energy and the other NRG Energy plan debtors. The second plan, relating to the Company, its subsidiaries and the South Central subsidiaries, referred to as the Northeast/ South Central Plan of Reorganization, was filed on September 17, 2003. On November 24, 2003, the bankruptcy court entered an order confirming NRG Energy’s Plan of Reorganization and the plan became effective on December 5, 2003. On November 25, 2003, the bankruptcy court issued an order confirming the Northeast/ South Central Plan of Reorganization and the plan became effective on December 23, 2003. In connection with NRG Energy’s emergence from bankruptcy, NRG Energy adopted fresh start accounting in accordance with AICPA Statement of Position 90-7,  Financial Reporting by Entities in Reorganization Under the Bankruptcy Code  (“SOP 90-7”) on December 5, 2003. NRG Energy’s fresh start accounting was applied to the Company on a push down accounting basis with the financial statement impact recorded as an adjustment to the December 6, 2003, members’ equity in the amount of $20.2 million.

 	NRG Energy’s Plan of Reorganization	
      NRG Energy’s Plan of Reorganization is the result of several months of intense negotiations among NRG Energy, Xcel Energy, Inc. (“Xcel Energy”) and the two principal committees representing NRG Energy creditor groups, referred to as the Global Steering Committee and the Noteholder Committee. A principal component of NRG Energy’s Plan of Reorganization is a settlement with Xcel Energy in which Xcel Energy agreed to make a contribution consisting of cash (and, under certain circumstances, its stock) in the aggregate amount of up to $640 million to be paid in three separate installments following the effective date of NRG Energy’s Plan of Reorganization. The Xcel Energy settlement agreement resolves any and all claims existing between Xcel Energy and NRG Energy and/or its creditors and, in exchange for the Xcel Energy contribution, Xcel Energy is receiving a complete release of claims from NRG Energy and its creditors, except for a limited number of creditors who have preserved their claims as set forth in the confirmation order entered on November 24, 2003.

 	Northeast/ South Central Plan of Reorganization	
      The Northeast/ South Central Plan of Reorganization was proposed on September 17, 2003, after necessary financing commitments were secured. On November 25, 2003, the bankruptcy court issued an order confirming the Northeast/ South Central Plan of Reorganization and the plan became effective on

8

 
NRG NORTHEAST GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

December 23, 2003. In connection with the order confirming the Northeast/ South Central Plan of Reorganization, the court entered a separate order which provides that the allowed amount of the bondholders’ claims shall equal in the aggregate the sum of (i) $1.3 billion plus (ii) any accrued and unpaid interest at the applicable contract rates through the date of payment to the indenture trustee plus (iii) the reasonable fees, costs or expenses of the collateral agent and indenture trustee (other than reasonable professional fees incurred from October 1, 2003) plus (iv) $19.6 million, ratably, for each holder of bonds based upon the current outstanding principal amount of the bonds and irrespective of (a) the date of maturity of the bonds, (b) the interest rate applicable to such bonds and (c) the issuer of the bonds.

      The creditors of Northeast and South Central subsidiaries were unimpaired by the Northeast/ South Central Plan of Reorganization. The creditors holding allowed general secured claims were paid in cash, in full on the effective date of the Northeast/ South Central Plan of Reorganization. Holders of allowed unsecured claims will receive or have received either (i) cash equal to the unpaid portion of their allowed unsecured claim, (ii) treatment that leaves unaltered the legal, equitable and contractual rights to which such unsecured claim entitles the holder of such claim, (iii) treatment that otherwise renders such unsecured claim unimpaired pursuant to section 1124 of the bankruptcy code or (iv) such other, less favorable treatment that is confirmed in writing as being acceptable to such holder and to the applicable debtor.

2.	Summary of Significant Accounting Policies	

 	Principles of Consolidation	
      The consolidated financial statements include the accounts of the Company and its subsidiaries. All significant intercompany transactions and balances have been eliminated in consolidation. Accounting policies for all of the Company’s operations are in accordance with the accounting principles generally accepted in the United States of America.

 	NRG Energy Fresh Start Reporting/Push Down Accounting	
      In accordance with SOP 90-7, certain companies qualify for fresh start (“Fresh Start”) reporting in connection with their emergence from bankruptcy. Fresh Start reporting is appropriate on the emergence from Chapter 11 if the reorganization value of the assets of the emerging entity immediately before the date of confirmation is less than the total of all post-petition liabilities and allowed claims, and if the holders of existing voting shares immediately before confirmation receive less than 50% of the voting shares of the emerging entity. NRG Energy met these requirements and adopted Fresh Start reporting and applied push down accounting to its various subsidiary operations including the Company. Under push down accounting, the Company’s equity fair value was allocated to the Company’s assets and liabilities based on their estimated fair values as of December 5, 2003, as further described in Note 3.

      Under the requirements of Fresh Start, NRG Energy adjusted its assets and liabilities, other than deferred income taxes, to their estimated fair values as of December 5, 2003. As a result of marking the assets and liabilities to their estimated fair values, NRG Energy determined that there was a negative reorganization value that was reallocated back to the tangible and intangible assets. Deferred taxes were determined in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 109,  Accounting for Income Taxes . The net effect of all Fresh Start adjustments resulted in a gain of $3.9 billion, which is reflected in NRG Energy’s Predecessor Company results for the period from January 1, 2003 to December 5, 2003. The application of the Fresh Start provisions of SOP 90-7 created a new reporting entity having no retained earnings or accumulated deficit.

      As part of the bankruptcy process, NRG Energy engaged an independent financial advisor to assist in the determination of its reorganized enterprise value. The fair value calculation was based on management’s forecast of expected cash flows from its core assets. Management’s forecast incorporated forward commodity

9

 
NRG NORTHEAST GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

market prices obtained from a third party consulting firm. A discounted cash flow calculation was used to develop the enterprise value of Reorganized NRG, determined in part by calculating the weighted average cost of capital of the Reorganized NRG. The Discounted Cash Flow, (“DCF,”) valuation methodology equates the value of an asset or business to the present value of expected future economic benefits to be generated by that asset or business. The DCF methodology is a “forward looking” approach that discounts expected future economic benefits by a theoretical or observed discount rate. The independent financial advisor prepared a 30-year cash flow forecast using a discount rate of approximately 11%. The resulting reorganization enterprise value as included in the Disclosure Statement ranged from $5.5 billion to $5.7 billion. The independent financial advisor then subtracted NRG Energy’s project level debt and made several other adjustments to reflect the values of assets held for sale, excess cash and collateral requirements to estimate a range of Reorganized NRG equity value of between $2.2 billion and $2.6 billion.

      In constructing the Fresh Start balance sheet upon emergence from bankruptcy, NRG Energy used a reorganization equity value of approximately $2.4 billion, as NRG Energy believed this value to be the best indication of the value of the ownership distributed to the new equity owners. NRG Energy’s Plan of Reorganization provided for the issuance of 100,000,000 shares of NRG Energy common stock to the various creditors resulting in a calculated price per share of $24.04. The reorganization value of approximately $9.1 billion was determined by adding the reorganized equity value of $2.4 billion, $3.7 billion of interest bearing debt and other liabilities of $3.0 billion. The reorganization value represents the fair value of an entity before liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after restructuring. This value is consistent with the voting creditors and Court’s approval of NRG Energy’s Plan of Reorganization.

      The application of SOP 90-7 and push down accounting resulted in the creation of a new reporting entity for the Company. Consequently, the consolidated financial statements of the Reorganized Company and the Predecessor Company are separated by a black line to distinguish that the assets, liabilities and equity as well as the results of operations are not comparable between periods. Under the requirements of push down accounting, the Company has adjusted its assets and liabilities to their estimated fair values as of December 5, 2003. The impact of push down accounting resulted in the reduction of members’ equity for the Company in the amount of $20.2 million.

      Between May 14, 2003 and December 23, 2003, the Company operated as a debtor in possession under the supervision of the bankruptcy court. The consolidated financial statements for reporting periods within that timeframe were prepared in accordance with the provisions of SOP 90-7.

      For financial reporting purposes, close of business on December 5, 2003, represents the date of NRG Energy’s emergence from bankruptcy. As previously stated, the Company and its subsidiaries emerged from bankruptcy on December 23, 2003. The accompanying consolidated financial statements reflect the impact of NRG Energy’s emergence from bankruptcy effective December 5, 2003. As used herein, the following terms refer to the Company and its operations:
 	 	 	
 	“Predecessor Company”	The Company, prior to push down accounting

The Company’s operations, January 1, 2001 - December 31, 2001

The Company’s operations, January 1, 2002 - December 31, 2002

The Company’s operations, January 1, 2003 - December 5, 2003	

 	“Reorganized Company”	The Company, post push down accounting

The Company’s operations, December 6, 2003 - December 31, 2003	
      The bankruptcy court in its confirmation order approved NRG Energy’s Plan of Reorganization on November 24, 2003, and subsequently approved the Company’s Plan of Reorganization on November 25,

10

 
NRG NORTHEAST GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

2003. Under the requirements of SOP 90-7, the Fresh Start date is determined to be the confirmation date unless significant uncertainties exist regarding the effectiveness of the bankruptcy order. NRG Energy’s Plan of Reorganization required completion of the Xcel Energy settlement agreement prior to emergence from bankruptcy. Management believes this settlement agreement was a significant contingency and thus delayed the Fresh Start date until the Xcel Energy settlement agreement was finalized on December 5, 2003.

 	Cash and Cash Equivalents	
      Cash and cash equivalents include highly liquid investments (primarily commercial paper) with a maturity of three months or less at the time of purchase.

 	Restricted Cash	
      Restricted cash consists primarily of funds held within the Company’s subsidiaries that are restricted in their use due to contractual arrangements.

 	Inventory	
      Inventory is valued at the lower of weighted average cost or market and consists principally of fuel oil, spare parts, coal and kerosene.

 	Property, Plant and Equipment	
      Property, plant and equipment are stated at cost; however, impairment adjustments are recorded whenever events or changes in circumstances indicate carrying values may not be recoverable. At December 5, 2003, the Company recorded adjustments to the property, plant and equipment to reflect such items at fair value in accordance with push down accounting. A new cost basis was established with these adjustments. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance that do not improve or extend the life of the respective asset are charged to expense as incurred. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. The assets and related accumulated depreciation amounts are adjusted for asset retirements and disposals with the resulting gain or loss included in operations.

 	Asset Impairments	
      Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate carrying values may not be recoverable. Such reviews are performed in accordance with SFAS No. 144,  Accounting for the Impairment or Disposal of Long-Lived Assets . An impairment loss is recognized if the total future estimated undiscounted cash flows expected from an asset are less than its carrying value. An impairment charge is measured by the difference between an asset’s carrying amount and fair value. Fair values are determined by a variety of valuation methods, including appraisals, sales prices of similar assets and present value techniques.

 	Debt Issuance Costs	
      Debt issuance costs consist of legal and other costs incurred by the Company to obtain long-term financing. These costs, which were written off as part of push down accounting (see Note 3), were capitalized and amortized as interest expense on a straight-line basis that approximates the effective interest method over the terms of the related debt.

11

 
NRG NORTHEAST GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 	Intangible Assets	
      Intangible assets represent contractual rights held by the Company. Intangible assets are amortized over their economic useful life and reviewed for impairment on a periodic basis.

      Intangible assets consist primarily of the fair value of power sales agreements and emission allowances. The amounts related to the power sales agreements will be amortized as a reduction to revenue over the terms and conditions of each contract. Emission allowance related amounts will be amortized as additional fuel expense based upon the actual level of emissions from the respective plant through 2023.

 	Revenue Recognition	
      Revenues from the sale of electricity are recorded based upon the output delivered and capacity provided at rates specified under contract terms or prevailing market rates. Revenues and related costs under cost reimbursable contract provisions are recorded as costs are incurred.

      In certain markets, which are operated/controlled by an independent system operator and in which the Company has entered into a netting agreement with the Independent System Operator (“ISO”), which results in receiving a netted invoice, the Company has recorded purchased energy as an offset against revenues received upon the sale of such energy. Capacity and ancillary revenue is recognized when contractually earned. Disputed revenues are not recorded in the financial statements until disputes are resolved and collection is assured.

 	Power Marketing Activities	
      The Company’s subsidiaries have entered into agency agreements with a marketing affiliate for the sale of energy, capacity and ancillary services produced by these subsidiaries, and for the procurement and management of fuel (coal, oil derivatives and natural gas) and emission credit allowances, which enables the affiliate to engage in forward sales and hedging transactions to manage the subsidiaries’ electricity and fuel price exposure. Net gains or losses on hedges by the marketing affiliate, which are physically settled, are recognized in the same manner as the hedged item. The Company receives the net transaction price on all contracts that are physically settled by its marketing affiliate.

 	Income Taxes	
      The Company has been organized as a limited liability company. Therefore, federal and state income taxes are assessed at the member level. However, a provision for separate company federal and state income taxes has been reflected in the accompanying consolidated financial statements (see Note 16 — Income Taxes). As a result of the Company being included in the NRG Energy consolidated tax return and tax payments, federal and state taxes payable amounts resulting from the tax provision are reflected as a contribution by members in the consolidated statement of members’ equity and consolidated balance sheets.

      Deferred income taxes are recognized for the tax consequences in future years of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts at each year end based on enacted tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. Income tax expense is the tax payable for the period and the change during the period in deferred tax assets and liabilities. A valuation allowance is recorded to reduce deferred tax assets to the amount more likely than not to be realized.

 	Concentrations of Credit Risk	
      Financial instruments, which potentially subject the Company to concentrations of credit risk, consist primarily of cash, accounts receivable and derivative instruments. Cash accounts are generally held in

12

 
NRG NORTHEAST GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

federally insured banks. Accounts receivable and derivative instruments are concentrated within entities engaged in the energy industry. These industry concentrations may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. Receivables are generally not collateralized; however, the Company believes the credit risk posed by industry concentration is mitigated by the diversification and credit worthiness of its customer base.

 	Fair Value of Financial Instruments	
      The carrying amount of cash and cash equivalents, restricted cash, receivables, accounts payables, debt and accrued liabilities approximate fair value because of the short maturity of these instruments. The fair value of long-term debt is estimated based on quoted market prices and similar instruments with equivalent credit quality.

 	Use of Estimates in Financial Statements	
      The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenue and expenses during the reporting period. Actual results could differ from these estimates.

      In recording transactions and balances resulting from business operations, the Company uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, uncollectible accounts, and the valuation of long-term energy commodities contracts, among others. In addition, estimates are used to test long-lived assets for impairment and to determine fair value of impaired assets. As better information becomes available (or actual amounts are determinable), the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

 	Reclassifications	
      Certain prior year amounts have been reclassified for comparative purposes. These reclassifications had no effect on the Company’s net income or total members’ equity as previously reported.

3.	Emergence from Bankruptcy and Fresh Start Reporting	
      In accordance with the requirement of push down accounting, the Company’s fair value of $650.7 million was allocated to the Company’s assets and liabilities based on their individual estimated fair values. A third party was used to complete an independent appraisal of the Company’s tangible assets, intangible assets and contracts.

      The determination of the fair value of the Company’s assets and liabilities was based on a number of estimates and assumptions, which are inherently subject to significant uncertainties and contingencies.

      Due to the adoption of push down accounting as of December 5, 2003, the Reorganized Company’s consolidated balance sheets, consolidated statements of operations and cash flows have not been prepared on a consistent basis with the Predecessor Company’s consolidated financial statements and are not comparable in certain respects to the consolidated financial statements prior to the application of push down accounting. A black line has been drawn on the accompanying consolidated financial statements to separate and distinguish

13

 
NRG NORTHEAST GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

between the Reorganized Company and the Predecessor Company. The effects of the push down accounting adjustments on the Company’s consolidated balance sheet as of December 5, 2003, were as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor	 	 	 	Reorganized	
 	 	Company	 	 	 	Company	

	 	 	 	

	
 	 	December 5,	 	Push Down	 	December 6,	
 	 	2003	 	Adjustments	 	2003	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
ASSETS	
Current assets	 	 	 	 	 	 	 	 	 	 	 	 	
 	Cash and cash equivalents	 	$	5,258	 	 	$	—	 	 	$	5,258	 	
 	Restricted cash	 	 	3,608	 	 	 	—	 	 	 	3,608	 	
 	Accounts receivable	 	 	306	 	 	 	—	 	 	 	306	 	
 	Accounts receivable — affiliates	 	 	24,349	 	 	 	—	 	 	 	24,349	 	
 	Inventory	 	 	131,940	 	 	 	(23,266	)(A)	 	 	108,674	 	
 	Prepayments and other current assets	 	 	29,426	 	 	 	—	 	 	 	29,426	 	
 	Current deferred income tax	 	 	38,157	 	 	 	(38,157	)(B)	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total current assets	 	 	233,044	 	 	 	(61,423	)	 	 	171,621	 	
Property, plant and equipment, net	 	 	1,057,063	 	 	 	(211,191	)(C)	 	 	845,872	 	
Intangible assets, net	 	 	21,223	 	 	 	192,987	(D)	 	 	214,210	 	
Deferred income tax	 	 	29,215	 	 	 	62,659	(B)	 	 	91,874	 	
Other assets	 	 	7,355	 	 	 	—	 	 	 	7,355	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total assets	 	$	1,347,900	 	 	$	(16,968	)	 	$	1,330,932	 	

	 	 	 	

	 	 	 	

	 	
 	
LIABILITIES AND MEMBERS’ EQUITY	
Current liabilities	 	 	 	 	 	 	 	 	 	 	 	 	
 	Current portion of long-term debt	 	$	556,500	 	 	$	—	 	 	$	556,500	 	
 	Note payable — affiliate	 	 	30,000	 	 	 	—	 	 	 	30,000	 	
 	Accounts payable	 	 	64	 	 	 	—	 	 	 	64	 	
 	Accrued interest	 	 	26,342	 	 	 	—	 	 	 	26,342	 	
 	Other accrued liabilities	 	 	59,344	 	 	 	—	 	 	 	59,344	 	
 	Derivative instruments valuation	 	 	95	 	 	 	—	 	 	 	95	 	
 	Current deferred income tax	 	 	—	 	 	 	442	(B)	 	 	442	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total current liabilities	 	 	672,345	 	 	 	442	 	 	 	672,787	 	
Other long-term obligations	 	 	4,749	 	 	 	2,744	(D)	 	 	7,493	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total liabilities	 	 	677,094	 	 	 	3,186	 	 	 	680,280	 	
Members’ equity	 	 	 	 	 	 	 	 	 	 	 	 	
 	Members’ contributions	 	 	748,991	 	 	 	(98,339	)	 	 	650,652	 	
 	Accumulated net loss	 	 	(78,185	)	 	 	78,185	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total members’ equity	 	 	670,806	 	 	 	(20,154	)(E)	 	 	650,652	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total liabilities and members’ equity	 	$	1,347,900	 	 	$	(16,968	)	 	$	1,330,932	 	

	 	 	 	

	 	 	 	

	 	

 
 	 	 	
(A)	 	Accounting policy change upon adoption of push down accounting. Consumables are no longer included as inventory and are expensed as incurred. In addition, capital spare parts of $5.6 million were reclassified from inventory to property, plant and equipment.	
 	 	 	
(B)	 	Reflects the adjustment to deferred income tax assets and liabilities due to push down accounting.	
14

 
NRG NORTHEAST GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(C)	 	Result of allocating the equity value in conformity with the purchase method of accounting for business combinations. These allocations were based on valuations obtained from independent appraisers.	
 	 	 	
(D)	 	Reflects management’s estimate, with the assistance of independent appraisers, of the fair value of power purchase agreements and SO2 emission credits. In addition, the Asset Retirement Obligation (“ARO”) was revalued.	
 	 	 	
(E)	 	The change in members’ equity reflects the fair value adjustment resulting from NRG Energy’s Fresh Start accounting procedures.	

4.	Other Charges	
      Restructuring and impairment charges and reorganization items included in operating costs and expenses in the consolidated statement of operations include the following:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the	
 	 	2003 through	 	2003 through	 	Year Ended	
 	 	December 31,	 	December 5,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Restructuring and impairment charges	 	$	—	 	 	$	230,571	 	 	$	50,524	 	
Reorganization items	 	 	241	 	 	 	5,148	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
 	 	$	241	 	 	$	235,719	 	 	$	50,524	 	

	 	 	 	

	 	 	 	

	 	

 	Restructuring and Impairment Charges	
      The Company reviewed the recoverability of its long-lived assets in accordance with the guidelines of SFAS No. 144. As a result of this review, the Company recorded pre-tax impairment charges of $230.6 million for the period from January 1, 2003 through December 5, 2003, and $49.3 million for the year ended December 31, 2002, as shown in the table below.

      To determine whether an asset was impaired, the Company compared asset carrying values to total future estimated undiscounted cash flows. Separate analyses were completed for assets or groups of assets at the lowest level for which identifiable cash flows were largely independent of the cash flows of other assets and liabilities. The estimates of future cash flows included only future cash flows, net of associated cash outflows, directly associated with and expected to arise as a result of the Company’s assumed use and eventual disposition of the asset. Cash flow estimates associated with assets in service were based on the asset’s existing service potential. The cash flow estimates may include probability weightings to consider possible alternative courses of action and outcomes, given the uncertainty of available information and prospective market conditions.

      If an asset was determined to be impaired based on the cash flow testing performed, an impairment loss was recorded to write down the asset to its fair value. Estimates of fair value were based on prices for similar assets and present value techniques. Fair values determined by similar asset prices reflect the Company’s current estimate of recoverability from expected marketing of project assets. For fair values determined by projected cash flows, the fair value represents a discounted cash flow amount over the remaining life of each project that reflects project-specific assumptions for long-term power pool prices, escalated future project operating costs, and expected plant operation given assumed market conditions.

15

 
NRG NORTHEAST GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      Restructuring and impairment charges included the following asset impairments for the period from January 1, 2003 to December 5, 2003 and for the year ended December 31, 2002:

 	 	Predecessor Company	 	 	

	 	 	
 	 	For the	 	 	 	 	
 	 	Period from	 	 	 	 	
 	 	January 1,	 	For the	 	 	
 	 	2003 through	 	Year Ended	 	 	
 	 	December 5,	 	December 31,	 	 	
 	 	2003	 	2002	 	Fair Value Basis	

	 	

	 	

	
 	 	 	 	 	
 	 	(In thousands of dollars)	 	 	
Devon Power LLC	 	$	64,198	 	 	$	—	 	 	 	Projected cash flows	 	
Middletown Power LLC	 	 	157,323	 	 	 	—	 	 	 	Projected cash flows	 	
Arthur Kill Power LLC	 	 	9,050	 	 	 	—	 	 	 	Projected cash flows	 	
Somerset Power LLC	 	 	—	 	 	 	49,289	 	 	 	Projected cash flows	 	

	 	 	 	

	 	 	 	 	 	
Total impairment charges	 	 	230,571	 	 	 	49,289	 	 	 	 	 	
Consulting fees related to pending bankruptcy	 	 	—	 	 	 	1,235	 	 	 	 	 	

	 	 	 	

	 	 	 	 	 	
Total restructuring and impairment charges	 	$	230,571	 	 	$	50,524	 	 	 	 	 	

	 	 	 	

	 	 	 	 	 	
     Connecticut Facilities — As a result of regulatory developments and changing circumstances in the second quarter of 2003, the Company updated the facilities’ cash flow models to incorporate changes to reflect the impact of the April 25, 2003, Federal Energy Regulatory Commission (“FERC”). FERC’s orders on Peaking Units Safe Harbor (“PUSH”) pricing, the pending termination of the Reliability Must Run Agreements (“RMR”), and to update the estimated impact of future locational capacity or deliverability requirements. Based on these revised cash flow models, management determined that the new estimates of pricing and cost recovery levels were not projected to return sufficient revenue to cover the fixed costs at Devon Power LLC and Middletown Power LLC. As a consequence, during the second quarter of 2003, the Company recorded a $64.2 million and $157.3 million impairment at Devon Power LLC and Middletown Power LLC, respectively.

     Arthur Kill Power LLC — During the third quarter of 2003, the Company cancelled its plans to re-establish fuel oil capacity at its Arthur Kill plant. This resulted in a charge of approximately $9.1 million to write-off assets under construction.

     Somerset Power LLC — The credit rating downgrades, defaults under certain credit agreements, increased collateral requirements and reduced liquidity experienced by NRG Northeast during the third quarter of 2002 were “triggering events” which, pursuant to SFAS No. 144, required the Company to review the recoverability of its long-lived assets. As a result, the Company determined that Somerset Power became impaired during the third quarter of 2002 and should be written down to fair market value. Accordingly, the Company recorded asset impairment charges of $49.3 million related to Somerset Power.

      There were no impairment charges for the period from December 6, 2003 to December 31, 2003.

 	Reorganization Items	
      In connection with the confirmation of the Northeast/South Central Plan of Reorganization, the debt held by the Company became an allowable claim. As a result, the Company incurred a charge of approximately $3.4 million to write-off related debt issuance costs as well as incurring a pre-payment charge of approximately $8.3 million for the refinancing transaction completed with the emergence from bankruptcy of the Company. The $8.3 million was expensed in November 2003, as it was determined to be an allowed claim at that time. The Company recorded a gain of $18.1 million related to the write-off of the remaining

16

 
NRG NORTHEAST GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

unrecognized gain on the interest rate lock entered into by the Company upon the issuance of the Company’s debt.
 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	Predecessor	
 	 	Company	 	Company	

	 	

	
 	 	For the	 	For the	
 	 	Period from	 	Period from	
 	 	December 6,	 	January 1,	
 	 	2003 to	 	2003 to	
 	 	December 31,	 	December 5,	
 	 	2003	 	2003	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Reorganization items	 	 	 	 	 	 	 	 	
 	Consulting and legal fees	 	$	241	 	 	$	(1,271	)	
 	Deferred financing costs	 	 	—	 	 	 	(3,350	)	
 	Pre-payment charge	 	 	—	 	 	 	(8,348	)	
 	Write-off of interest rate lock	 	 	—	 	 	 	18,117	 	

	 	 	 	

	 	
 	 	Total reorganization items	 	$	241	 	 	$	5,148	 	

	 	 	 	

	 	

5.	Inventory	
      Inventory, which is valued at the lower of weighted average cost or market, consists of:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Fuel oil	 	$	66,915	 	 	$	65,462	 	 	$	47,052	 	
Spare parts	 	 	24,947	 	 	 	24,986	 	 	 	59,524	 	
Coal	 	 	12,163	 	 	 	14,815	 	 	 	14,378	 	
Kerosene	 	 	3,416	 	 	 	3,411	 	 	 	2,852	 	
Other	 	 	—	 	 	 	—	 	 	 	157	 	

	 	 	 	

	 	 	 	

	 	
 	Total inventory	 	$	107,441	 	 	$	108,674	 	 	$	123,963	 	

	 	 	 	

	 	 	 	

	 	
17

 
NRG NORTHEAST GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

6.	Property, Plant and Equipment	
      The major classes of property, plant and equipment were as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Predecessor	 	 	
 	 	 	 	Reorganized Company	 	Company	 	Average	

	 	

	 	Remaining	
 	 	Depreciable	 	December 31,	 	December 6,	 	December 31,	 	Useful	
 	 	Lives	 	2003	 	2003	 	2002	 	Life	

	 	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Facilities, machinery and equipment	 	 	25-30 years	 	 	$	802,173	 	 	$	802,492	 	 	$	1,415,726	 	 	 	18 years	 	
Land and improvements	 	 	 	 	 	 	34,266	 	 	 	34,266	 	 	 	46,925	 	 	 	 	 	
Construction in progress	 	 	 	 	 	 	9,689	 	 	 	8,499	 	 	 	27,615	 	 	 	 	 	
Office furnishings and equipment	 	 	3-10 years	 	 	 	615	 	 	 	615	 	 	 	1,196	 	 	 	2 years	 	

	 	 	 	

	 	 	 	

	 	 	 	 	 	
 	Total property, plant and equipment	 	 	 	 	 	 	846,743	 	 	 	845,872	 	 	 	1,491,462	 	 	 	 	 	
Accumulated depreciation	 	 	 	 	 	 	(2,911	)	 	 	—	 	 	 	(157,534	)	 	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	 	 	
Property, plant and equipment, net	 	 	 	 	 	$	843,832	 	 	$	845,872	 	 	$	1,333,928	 	 	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	 	 	

7.	Asset Retirement Obligation	
      Effective January 1, 2003, the Company adopted SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires an entity to recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred. Upon initial recognition of a liability for an asset retirement obligation, an entity shall capitalize an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes and written or oral contracts, including obligations arising under the doctrine of promissory estoppel.

      The Company identified certain retirement obligations related to environmental obligations for ash disposal site closures. The Company also identified similar other asset retirement obligations that could not be calculated because the assets associated with the retirement obligations were determined to have an indeterminate life. The adoption of SFAS No. 143 resulted in recording a $0.2 million increase to property, plant and equipment and a $0.3 million increase to other long-term obligations. The cumulative effect of adopting SFAS No. 143 was recorded as a $0.1 million increase to depreciation expense and a $0.1 million increase to operating costs in the period from January 1, 2003 to December 5, 2003, as the Company considered the cumulative effect to be immaterial.

      The following represents the balances of the asset retirement obligation at January 1, 2003, and the additions and accretion of the asset retirement obligation for the period from January 1, 2003 to December 5, 2003 and the period from December 6, 2003 to December 31, 2003, which is included in other long-term obligations in the consolidated balance sheet. Prior to December 5, 2003, the Company completed its annual review of asset retirement obligations. As part of that review, the Company identified new obligations in the amount of $4.0 million. As a result of applying push down accounting, the Company revalued its asset retirement obligations on December 6, 2003. The Company recorded an increase to its retirement obligation of

18

 
NRG NORTHEAST GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

$2.7 million in connection with push down accounting. This amount results from a change in the discount rate used between adoption and December 5, 2003, equal to 500 to 600 basis points.

 	 	Predecessor Company	

	
 	 	 	 	Accretion	 	 	
 	 	Beginning	 	 	 	for Period	 	Adjustment	 	Ending	
 	 	Balance	 	 	 	Ended	 	for	 	Balance	
 	 	January 1,	 	Revisions	 	December 5,	 	Fresh Start	 	December 5,	
 	 	2003	 	to Estimate	 	2003	 	Reporting	 	2003	

	 	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Dunkirk Power LLC	 	$	—	 	 	$	1,609	 	 	$	136	 	 	$	920	 	 	$	2,665	 	
Huntley Power LLC	 	 	—	 	 	 	2,426	 	 	 	225	 	 	 	1,675	 	 	 	4,326	 	
Someset Power LLC	 	 	313	 	 	 	—	 	 	 	40	 	 	 	149	 	 	 	502	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	$	313	 	 	$	4,035	 	 	$	401	 	 	$	2,744	 	 	$	7,493	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	

 	 	Reorganized Company	

	
 	 	 	 	Accretion for	 	 	
 	 	Beginning	 	Period	 	Ending	
 	 	Balance	 	December 6 to	 	Balance	
 	 	December 6,	 	December 31,	 	December 31,	
 	 	2003	 	2003	 	2003	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Dunkirk Power LLC	 	$	2,665	 	 	$	12	 	 	$	2,677	 	
Huntley Power LLC	 	 	4,326	 	 	 	20	 	 	 	4,346	 	
Somerset Power LLC	 	 	502	 	 	 	3	 	 	 	505	 	

	 	 	 	

	 	 	 	

	 	
 	 	$	7,493	 	 	$	35	 	 	$	7,528	 	

	 	 	 	

	 	 	 	

	 	
      The following represents the pro forma effect on the Company’s net income for the period from January 1, 2003 to December 5, 2003, and for the years ended December 31, 2002 and 2001, as if the Company had adopted SFAS No. 143 as of January 1, 2001:

 	 	Predecessor Company	

	
 	 	For the	 	 	
 	 	Period from	 	 	
 	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	December 31,	
 	 	December 5,	 	

	
 	 	2003	 	2002	 	2001	

	 	

	 	

	
 	 	 	 	(As Restated)	 	(As Restated)	
 	 	 	
 	 	(In thousands of dollars)	
Net (loss) income as reported	 	$	(145,687	)	 	$	425	 	 	$	119,804	 	
Pro forma adjustment to reflect retroactive adoption of SFAS No. 143	 	 	188	 	 	 	(56	)	 	 	(132	)	

	 	 	 	

	 	 	 	

	 	
Pro forma net (loss) income	 	$	(145,499	)	 	$	369	 	 	$	119,672	 	

	 	 	 	

	 	 	 	

	 	
      On a pro forma basis, an asset retirement obligation of $0.3 million and $0.3 million would have been recorded as an other long-term obligation at January 1, 2002 and December 31, 2002, respectively, based on similar assumptions used to determine the amounts on the Company’s consolidated balance sheets at December 6, 2003 and December 31, 2003.

8.	Intangible Assets	
      During the first quarter of 2002, the Company adopted SFAS No. 142, Goodwill and Other Intangible Assets, which requires new accounting for intangible assets, including goodwill. Intangible assets with finite

19

 
NRG NORTHEAST GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

lives will be amortized over their economic useful lives and periodically reviewed for impairment. Goodwill will no longer be amortized, but will be tested for impairment annually and on an interim basis if an event occurs or a circumstance changes between annual tests that may reduce the fair value of a reporting unit below its carrying value. The Company did not recognize any asset impairments as a result of adopting SFAS No. 142.

 	Reorganized Company	
      The Company had intangible assets with a net carrying value of $214.2 million and $213.7 million at December 6, 2003 and December 31, 2003, respectively. The power sales agreement amounts will be amortized as a reduction to revenue over the terms and conditions of each contract. The amortization period is six months for the power sales agreement. Emission allowances will be amortized as additional fuel expense based upon the actual level of emissions from the respective plant through 2023. No amortization was recorded during the period from December 6, 2003 to December 31, 2003, as this balance includes only emission allowances for 2004 and beyond. All emission allowances for 2003 were used prior to December 5, 2003. The amortization expense for the period from December 6, 2003 to December 31, 2003, was $0.5 million related to power sales agreements. The annual aggregate amortization expense for each of the five succeeding years is expected to approximate $15.1 million in year one and $13.2 million in years two through five for both the power sales agreements and emission allowances. Intangible assets consisted of the following:

 	 	Reorganized Company	 	Predecessor Company	

	 	

	
 	 	 	 	 	 	 	
 	 	December 31, 2003	 	December 6, 2003	 	December 31, 2002	

	 	

	 	

	
 	 	Gross	 	 	 	Gross	 	 	 	Gross	 	 	
 	 	Carrying	 	Accumulated	 	Carrying	 	Accumulated	 	Carrying	 	Accumulated	
 	 	Amount	 	Amortization	 	Amount	 	Amortization	 	Amount	 	Amortization	

	 	

	 	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Intangible assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Future transmission service	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	26,000	 	 	$	2,605	 	
 	Power sales agreements	 	 	3,140	 	 	 	523	 	 	 	3,140	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	Emission allowances	 	 	211,070	 	 	 	—	 	 	 	211,070	 	 	 	—	 	 	 	—	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Total intangible assets	 	$	214,210	 	 	$	523	 	 	$	214,210	 	 	$	—	 	 	$	26,000	 	 	$	2,605	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	

 	Predecessor Company	
      The Company had intangible assets with a carrying amount of $23.4 million at December 31, 2002, comprised of future transmission service being provided under a long-term contract. Amortization expense recognized for the years ended December 31, 2002 and 2001, was approximately $0.9 million and $1.7 million respectively. The amortization expense for the period from January 1, 2003 to December 5, 2003, was $2.2 million. The net amount of the intangible assets was transferred to fixed assets as part of push down accounting.

9.	Long-Term Debt and Note Payable — Affiliate	
      On February 22, 2000, the Company issued $750 million of project level senior secured bonds, to refinance short-term project borrowings and for certain other purposes. The bond offering included three tranches: $320 million with an interest rate of 8.065% due in 2004, $130 million with an interest rate of 8.842% due in 2015 and $300 million with an interest rate of 9.292% due in 2024. Interest and principal payments are due semi-annually. The bonds were jointly and severally guaranteed by each of the Company’s subsidiaries. The bonds were secured by a security interest in the Company’s membership or other ownership interests in the guarantors and its rights under all inter-company notes between the Company and the guarantors. In

20

 
NRG NORTHEAST GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

December 2000, the Company exchanged all of its outstanding bonds for bonds registered under the Securities Act of 1933. As a result of the Company’s failure to make the December 15, 2002 principal payment and other default provisions, the entire $556.5 million owed on the secured bonds was classified as a current liability at December 6, 2003 and December 31, 2002. On December 23, 2003, NRG Energy issued $1.25 billion in Second Priority Notes, due and payable on December 15, 2013. On the same date, NRG Energy also entered into a new credit facility for up to $1.45 billion. In addition, on December 23, 2003, the Company used proceeds of $570.1 million from a capital contribution from NRG Energy to pay the outstanding balance of $556.6 million along with the $1.1 million in accrued interest and $8.3 million in a pre-payment charge.

      On June 15, 2002, NRG Energy loaned the Company $30 million to fund capital expenditures. The debt bears interest at the three-month London Interbank Offered Rate plus 0.5%. The debt is subject to the terms and conditions of the senior secured bonds’ indenture. The debt was repaid in the first quarter of 2004. Accordingly, the Company has classified this loan as a short-term affiliated note payable.

10.	Derivative Instruments and Hedging Activity	
      On January 1, 2001, the Company adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 137, SFAS No. 138 and SFAS No. 149. SFAS No. 133 requires the Company to record all derivatives on the consolidated balance sheet at fair value. Changes in the fair value of nonhedge derivatives will be immediately recognized in earnings. The criteria used to determine if hedge accounting treatment is appropriate are (a) the designation of the hedge to an underlying exposure, (b) whether or not the overall risk is being reduced and (c) if there is a high degree of correlation between the value of the derivative instrument and the underlying obligation. Formal documentation of the hedging relationship, the nature of the underlying risk, the risk management objective, and the means by which effectiveness will be assessed is created at the inception of the hedge. Changes in fair values of derivatives accounted for as hedges will either be recognized in earnings as offsets to the changes in fair value of related hedged assets, liabilities and firm commitments or, for forecasted transactions, deferred and recorded as a component of other accumulated comprehensive income, (“OCI,”) until the hedged transactions occur and are recognized in earnings. The ineffective portion of a hedging derivative instrument’s change in fair value will be immediately recognized in earnings. The Company also formally assesses both at inception and at least quarterly thereafter, whether the derivatives that are used in hedging transactions are highly effective in offsetting the changes in either the fair value or cash flows of the hedged item. This assessment includes all components of each derivative’s gain or loss unless otherwise noted. When it is determined that a derivative ceases to be a highly effective hedge, hedge accounting is discontinued.

      SFAS No. 133 applies to the Company’s long-term power sales contracts, long-term gas purchase contracts and other energy related commodities financial instruments used to mitigate variability in earnings due to fluctuations in spot market prices, hedge fuel requirements at generation facilities and protect investments in fuel inventories. At December 31, 2003, the Company had various commodity contracts extending through April 2004.

21

 
NRG NORTHEAST GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 	Accumulated Other Comprehensive Income	
      The following table summarizes the effects of SFAS No. 133 on the Company’s accumulated other comprehensive income balance at December 31, 2003, December 6, 2003 and December 31, 2002:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Year	
 	 	2003 to	 	2003 to	 	Ended	
 	 	December 31,	 	December 5,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Energy Commodities Gains (Losses)	 	 	 	 	 	 	 	 	 	 	 	 	
Beginning balance	 	$	—	 	 	$	28,835	 	 	$	107,741	 	
 	Unwound from OCI during period	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Due to unwinding of previously deferred amounts	 	 	—	 	 	 	(28,835	)	 	 	(48,086	)	
 	Mark to market of hedge contracts	 	 	—	 	 	 	—	 	 	 	(30,820	)	

	 	 	 	

	 	 	 	

	 	
Ending balance	 	$	—	 	 	$	—	 	 	$	28,835	 	

	 	 	 	

	 	 	 	

	 	
Gains expected to unwind from OCI during next 12 months	 	$	—	 	 	$	—	 	 	$	28,835	 	

	 	 	 	

	 	 	 	

	 	
      During the period from January 1, 2003 to December 5, 2003 and for the year ended December 31, 2002, the Company reclassified gains of $28.8 million and $48.1 million, respectively, from OCI to current-period earnings. This amount is recorded on the same line in the statement of operations in which the hedged item is recorded. Also during the year ended December 31, 2002, the Company recorded losses in OCI of approximately $30.8 million related to changes in the fair values of derivatives accounted for as hedges. The net balance in OCI relating to SFAS No. 133 at December 31, 2002, was a gain of approximately $28.8 million.

 	Statement of Operations	
      The following tables summarize the effects of SFAS No. 133 on the Company’s statement of operations for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003, and for the years ended December 31, 2002 and 2001, respectively:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Energy Commodities Gains (Losses)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues	 	$	3	 	 	$	18,241	 	 	$	(10,706	)	 	$	(7,630	)	
Operating costs	 	 	513	 	 	 	(1,565	)	 	 	25,163	 	 	 	(23,597	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	Total statement of operations impact before tax	 	$	516	 	 	$	16,676	 	 	$	14,457	 	 	$	(31,227	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
22

 
NRG NORTHEAST GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Energy Commodities Gains (Losses)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net gain (loss) recognized in earnings due to	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Instruments not accounted for as hedges	 	$	516	 	 	$	16,676	 	 	$	14,457	 	 	$	(31,227	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total statement of operations impact before tax	 	$	516	 	 	$	16,676	 	 	$	14,457	 	 	$	(31,227	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	

 	Energy and Energy Related Commodities	
      The Company is exposed to commodity price variability in electricity, emission allowances, natural gas, oil derivatives and coal used to meet fuel requirements. In order to manage these commodity price risks, the Company may enter into transactions for physical delivery of particular commodities for a specific period. Financial instruments are used to hedge physical deliveries, which may take the form of fixed price, floating price or indexed sales or purchases, and options, such as puts, calls, basis transactions and swaps.

      During the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003, and the years ended December 31, 2002 and 2001, respectively, the Company recognized no gain or loss due to ineffectiveness of commodity cash flow hedges.

      The Company’s earnings for the period from December 6, 2003 to December 31, 2003 and the period from January 1, 2003 to December 5, 2003, were increased by unrealized gains of $0.5 million and $16.7 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. The Company’s earnings for the years ended December 31, 2002 and 2001, were increased by an unrealized gain of $14.5 million and decreased by an unrealized loss of $31.2 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.

11.	Financial Instruments	
      The estimated fair values of the Company’s recorded financial instruments are as follows:

 	 	Reorganized Company	 	Predecessor Company	

	 	

	
 	 	 	 	 	 	 	
 	 	December 31, 2003	 	December 6, 2003	 	December 31, 2002	

	 	

	 	

	
 	 	Carrying	 	Fair	 	Carrying	 	Fair	 	Carrying	 	Fair	
 	 	Amount	 	Value	 	Amount	 	Value	 	Amount	 	Value	

	 	

	 	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Cash and cash equivalents	 	$	6,250	 	 	$	6,250	 	 	$	5,258	 	 	$	5,258	 	 	$	14,354	 	 	$	14,354	 	
Restricted cash	 	 	4,198	 	 	 	4,198	 	 	 	3,608	 	 	 	3,608	 	 	 	—	 	 	 	—	 	
Long-term debt, including current portion	 	 	—	 	 	 	—	 	 	 	556,500	 	 	 	556,500	 	 	 	556,500	 	 	 	486,250	 	
Note payable — affiliate	 	 	30,000	 	 	 	30,000	 	 	 	30,000	 	 	 	30,000	 	 	 	30,000	 	 	 	30,000	 	
      For cash and cash equivalents and restricted cash, the carrying amount approximates fair value because of the short-term maturity of those instruments. The fair value of long-term debt is estimated based on the quoted market prices for similar issues. The fair value of notes payable — affiliates approximates carrying value as the underlying instruments bear a variable market interest rate.

23

 
NRG NORTHEAST GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

12.	Related Party Transactions	
      The Company’s subsidiaries have entered into agency agreements with NRG Power Marketing Inc. (“NRG Power Marketing”), a wholly owned subsidiary of NRG Energy. The agreements are effective until December 31, 2030. Under the agreements, NRG Power Marketing will (i) have the exclusive right to manage, market, hedge and sell all power not otherwise sold or committed to by such subsidiaries, (ii) procure, provide and hedge for such subsidiaries all fuel required to operate their respective facilities and (iii) market, sell and purchase all emission credits owned, earned or acquired by such subsidiaries. In addition, NRG Power Marketing will have the exclusive right and obligation to effect the dispatch of the power output from the facilities.

      Under the agreements, NRG Power Marketing pays to the subsidiaries gross receipts generated through sales, less costs incurred by NRG Power Marketing relative to its providing services (e.g. transmission and delivery costs, fuel cost, taxes, labor, contract services, etc.). The Company incurs no fees related to these power sales and agency agreements with NRG Power Marketing.

      The Company has no employees and has entered into operation and maintenance agreements with subsidiaries of NRG Operating Services, Inc., (“NRG Operating Services”) a wholly owned subsidiary of NRG Energy. The agreements are effective for five years, with options to extend beyond five years. Under the agreements, the NRG Operating Services company operator operates and maintains its respective facility, including (i) coordinating fuel delivery, unloading and inventory, (ii) managing facility spare parts, (iii) meeting external performance standards for transmission of electricity, (iv) providing operating and maintenance consulting and (v) cooperating with and assisting the Company in performing the Company’s obligations under agreements related to its facilities.

      Under the agreements, the operator charges an annual fee, and in addition, will be reimbursed for usual and customary costs related to providing the services including plant labor and other operating costs. A demobilization payment will be made if the subsidiary elects not to renew the agreement. There are also incentive fees and penalties based on performance under the approved operating budget, the heat rate and safety.

      During the period from December 6, 2003 to December 31, 2003, and the period from January 1, 2003 to December 5, 2003, the Company incurred operating costs billed from NRG Operating Services totaling $13.1 million and $169.7 million, respectively. For the years ended December 31, 2002 and 2001, the Company incurred operating costs billed from NRG Operating Services totaling $147.5 million and $162.1 million, respectively.

      The Company’s subsidiaries have entered into agreements with NRG Energy for corporate support and services. The agreements are perpetual in term, unless terminated in writing by a subsidiary. Under the agreements, NRG Energy will provide services, as requested, in areas such as human resources, accounting, finance, treasury, tax, office administration, information technology, engineering, construction management, environmental, legal and safety. Under the agreements, NRG Energy is paid for personnel time as well as out-of-pocket costs. These costs are reflected in general and administrative expenses in the consolidated statements of operations.

      For the period from January 1, 2003 to December 5, 2003, and for the period from December 6, 2003 to December 31, 2003, the Company incurred charges from NRG Energy of $9.7 million and $2.5 million, respectively. For the years ended December 31, 2002 and 2001, the Company paid NRG Energy approximately $4.2 million and $5.1 million, respectively, for corporate support and services.

24

 
NRG NORTHEAST GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

13.	Sales to Significant Customers	
      For the period from December 6, 2003 to December 31, 2003, two customers accounted for 60.7% (NYISO) and 28.7% (ISO New England) of total revenues. During the period from January 1, 2003 to December 5, 2003, two customers accounted for 80% (NYISO) and 19.3% (Connecticut Light and Power) of total revenues. During 2002, one customer, NYISO, accounted for 72.5% of NRG Northeast’s gross revenues. During 2001, two customers accounted for 72.5% of NRG Northeast’s total revenues, NYISO (58.4%) and Niagara Mohawk Power Corporation (14.1%). Such amounts include revenues from customers under contract with NRG Power Marketing.

14.	Commitments and Contingencies	

 	Operating Lease Commitments	
      The Company leases certain of its storage space and equipment under operating leases expiring on various dates through 2006. Rental expense under these operating leases was approximately $0, $0.9 million, $0.8 million and $0.9 million for the period from December 6, 2003 to December 31, 2003, for the period from January 1, 2003 to December 5, 2003, and for the years ending December 31, 2002 and 2001, respectively. Future minimum lease commitments under these leases for the years ending after December 31, 2003, are as follows:
 	 	 	 	 	
 	 	(In thousands	
 	 	of dollars)	
2004	 	$	237	 	
2005	 	 	222	 	
2006	 	 	176	 	

 	Environmental Matters	
      The construction and operation of power projects are subject to stringent environmental and safety protection and land use laws and regulations in the United States. These laws and regulations generally require lengthy and complex processes to obtain licenses, permits and approvals from federal, state and local agencies. If such laws and regulations become more stringent and NRG Northeast’s facilities are not exempted from coverage, NRG Northeast could be required to make extensive modifications to further reduce potential environmental impacts. Also, NRG Northeast could be held responsible under environmental and safety laws for the cleanup of pollutant releases at its facilities or at off-site locations where it has sent wastes.

      NRG Northeast and its subsidiaries strive to exceed the standards of compliance with applicable environmental and safety regulations. Nonetheless, NRG Northeast expects that future liability under or compliance with environmental and safety requirements could have a material effect on its operations or competitive position. It is not possible at this time to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of possible changes to environmental and safety regulations, regulatory interpretations or enforcement policies. 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 NRG Northeast’s operations.

      As part of acquiring existing generating assets, NRG Northeast 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 governmental priorities or (e) selection of a less expensive compliance option than originally envisioned.

25

 
NRG NORTHEAST GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      In response to liabilities associated with these activities, NRG Northeast has established accruals where reasonable estimates of probable liabilities are possible. At December 31, 2003, December 6, 2003 and December 31, 2002, NRG Northeast has established such accruals in the amount of approximately $3.8 million, primarily related to its Arthur Kill and Astoria projects. NRG Northeast adjusts the accruals when new remediation responsibilities are discovered and probable costs become estimable, or when current remediation estimates are adjusted to reflect new information.

      Under various federal, state and local environmental laws and regulations, a current or previous owner or operator of any facility, including an electric generating 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, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended by the Superfund Amendments and Reauthorization Act of 1986, impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and courts have interpreted liability under such laws to be strict (without fault) and joint and several. The cost of investigation, remediation or removal of any hazardous or toxic substances or petroleum products could be substantial. Although NRG Northeast has been involved in on-site contamination matters, to date, NRG Northeast has not been named as a potentially responsible party with respect to any off-site waste disposal matter.

      Coal ash is produced as a by-product of coal combustion at the Dunkirk, Huntley, and Somerset Generating Stations. NRG Northeast attempts to direct its coal ash to beneficial uses. Even so, significant amounts of ash are landfilled at on-site and off-site locations. At Dunkirk and Huntley, ash is disposed at landfills owned and operated by NRG Northeast. No material liabilities outside the costs associated with closure, post-closure care and monitoring are expected at these facilities. NRG Northeast maintains financial assurance to cover costs associated with closure, post-closure care and monitoring activities. In the past, NRG Northeast has provided financial assurance via financial test and corporate guarantee. As a result of NRG Energy’s debt restructuring, NRG Northeast was required to re-establish financial assurance via an instrument requiring complete collateralization of closure and post-closure-related costs, such costs currently estimated at approximately $5.8 million. NRG Northeast provided such financial assurance via a trust fund established in this amount on April 30, 2003.

      NRG Northeast must also maintain financial assurance for closing interim status Resource Conservation and Recovery Act facilities at the Devon, Middletown, Montville and Norwalk Generating Stations. Previously, NRG Northeast has provided financial assurance via financial test. As a result of NRG Energy’s debt restructuring, NRG Northeast was required to re-establish financial assurance via an instrument requiring complete collateralization of closure and post-closure-related costs, such costs currently estimated at approximately $1.5 million. NRG Northeast provided such financial assurance via a trust fund established in this amount on April 30, 2003.

      Historical clean-up liabilities were inherited as a part of acquiring the Somerset, Devon, Middletown, Montville, Norwalk, Arthur Kill and Astoria Generating Stations. NRG Northeast has recently satisfied clean-up obligations associated with the Ledge Road property (inherited as part of the Somerset acquisition). Site contamination liabilities arising under the Connecticut Transfer Act at the Devon, Middletown, Montville and Norwalk Stations have been identified and are currently being refined as part of on-going site investigations. NRG Northeast does not expect to incur material costs associated with completing the investigations at these stations or future work to cover and monitor landfill areas pursuant to the Connecticut requirements. Remedial obligations at the Arthur Kill Generating Station have been established in discussions between NRG Northeast and the New York State DEC and are estimated at $1.0 million. Remedial

26

 
NRG NORTHEAST GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

investigations are on going at the Astoria Generating Station. At this time, NRG Northeast’s long-term cleanup liability at this site is estimated at $1.5 million.

      At December 31, 2003, December 6, 2003 and December 31, 2002, the Company had recorded an accrual in the amount of $2.1 million to cover penalties associated with historical opacity exceedances.

 	Contractual Commitments	
      In connection with the acquisition of certain generating facilities NRG Northeast entered into various long-term transition agreements and standard offer agreements that obligated NRG Northeast to provide its customers, primarily the previous owners of the acquired facilities, with a certain portion of the energy and capacity output of the acquired facilities.

      During 1999, NRG Northeast acquired the Huntley and Dunkirk generating facilities from Niagara Mohawk Power Corporation (“NiMo”). In connection with this acquisition, NRG Northeast entered into a four-year agreement with NiMo that requires NRG Northeast to provide to NiMo pursuant to a predetermined schedule fixed quantities of energy and capacity at a fixed price. The contract expired in June 2003 and was recorded as a cash flow hedge for financial reporting purposes (Note 10).

      During 1999, the Company acquired certain generating facilities from Connecticut Light and Power Company (“CL&P”). NRG Power Marketing also entered into a four-year standard offer agreement that required NRG Power Marketing to provide to CL&P a portion of its load requirements through the year 2003 at a fixed rate of $43.83 per MWh. Through its agency agreement with the Company, NRG Power Marketing utilizes the capacity available in the Connecticut facilities in order to serve the contract. This agreement ended in December 2003.

      During 1999, the Company acquired the Oswego generating facilities from NiMo and entered into a four-year transition power sales contract with NiMo in order to hedge NiMo’s transition to market rates. Under the agreement, NiMo will pay to Oswego Power a fixed monthly price plus start up fees for the right to claim, at a specified delivery point(s), the installed capacity of unit 5 and for the right to exercise an option for an additional 350 MW of installed capacity. This agreement expired in October 2003.

      NRG Power Marketing has entered into a wholesale standard offer service agreement with Blackstone Valley Electric Company, Eastern Edison Company and Newport Electric Corporation (collectively the “EUA Companies”). Under the agreement, NRG Power Marketing is obligated to provide each of the EUA Companies with firm all-requirements electric service, including capacity, energy, reserves, line losses and related services necessary to serve the aggregate load attributable to retail customers taking standard offer service. The price the EUA Companies pay to NRG Power Marketing for each unit of electricity is a fixed price plus a fuel adjustment factor.

      In July 2002, NRG Power Marketing reached a tentative agreement with CL&P that would result in increased compensation to NRG Power Marketing, a supplier of CL&P’s wholesale supply agreement. CL&P filed an emergency petition with the Connecticut Department of Public Utility Control (“DPUC”) asking for approval of a shift of wholesale supply agreement revenues, effective August 1, 2002 through December 31, 2003, that would reallocate 0.7 cents per kilowatt-hour in the wholesale price paid to existing suppliers. On July 26, 2002, the DPUC denied the request of CL&P for an emergency letter ruling (see Note 15 — Regulatory Issues).

 	NYISO Claims	
      In November 2002, the NYISO notified the Company of claims related to New York City mitigation adjustments, general NYISO billing adjustments and other miscellaneous charges related to sales between November 2000 and October 2002. The New York City mitigation adjustments totaled $11.5 million. NRG

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NRG NORTHEAST GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Northeast did not contest that claim and it has been fully reserved. The general NYISO billing adjustment issue totaled $10.2 million and related to NYISO’s concern that the Company would not have sufficient revenue to cover subsequent revisions to its energy market settlements. At December 31, 2003, the NYISO held $4.5 million in escrow for such future settlement revision.

 	Guarantees	
      In November 2002, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation (“FIN”) No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.  The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor’s fiscal year end. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002. The interpretation addresses the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees. The interpretation also clarifies the requirements related to the recognition of a liability by a guarantor at the inception of the guarantee for the obligations the guarantor has undertaken in issuing the guarantee.

      In connection with push down accounting, all outstanding guarantees were considered new; accordingly, the Company applied the provisions of FIN 45 to all of those guarantees. Each guarantee was reviewed for the requirement to recognize a liability at inception.

      The Company is directly liable for the obligations of certain of its affiliates pursuant to guarantees relating to certain of their performance obligations. In addition, in connection with the purchase and sale of fuel, emission credits and power generation products to and from third parties with respect to the operation of some of the Company’s generation facilities, the Company may be required to guarantee a portion of the obligations of certain of its subsidiaries. The Company also provides performance guarantees to third parties on behalf of NRG Power Marketing in relation to certain of its sales and supply agreements.

      At December 31, 2003, the Company’s obligations pursuant to its guarantees of the performance obligations of its affiliates and subsidiaries totaled approximately $7.3 million. No amount has been recorded as a liability as of December 31, 2003.

      The nature and details of the Company’s guarantees were as follows:
 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantee/	 	Guarantee/	 	 	 	 	 	 	
 	 	Maximum	 	Maximum	 	 	 	 	 	 	
 	 	Exposure —	 	Exposure —	 	 	 	 	 	 	
 	 	December 6,	 	December 31,	 	Nature of	 	 	 	 	
Name	 	2003	 	2003	 	Guarantee	 	Expiration Date	 	Triggering Event	

	 	

	 	

	 	

	 	

	 	

	
 	 	 	 	 	 	 	 	 	
 	 	(In thousands of dollars)	 	 	 	 	 	 	
Astoria/ Arthur Kill	 	Indeterminate	 	Indeterminate	 	Performance	 	None stated	 	Nonperformance	
Devon/ Middletown/ Montville/ Norwalk	 	$2,339	 	$2,339	 	Performance	 	None stated	 	Nonperformance	
NRG Power Marketing, as agent for NRG Northeast	 	$5,000	 	$5,000	 	Performance	 	March 31, 2004	 	Nonperformance	
      In addition to these guarantees, the Company is a guarantor under the debt issued by the Company’s ultimate parent, NRG Energy. NRG Energy issued $1.25 billion of 8% Second Priority Notes on December 23, 2003, due and payable on December 15, 2013. On January 28, 2004, NRG Energy also issued $475.0 million of Second Priority Notes, under the same terms and indenture as its December 23, 2003 offering.

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NRG NORTHEAST GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      NRG Energy’s payment obligations under the notes and all related Parity Lien Obligations are guaranteed on an unconditional basis by each of NRG Energy’s current and future restricted subsidiaries, of which the Company is one. The notes are jointly and severally guaranteed by each of the guarantors. The subsidiary guarantees of the notes are secured, on a second priority basis, equally and ratably with any future Parity Lien Debt, by security interests in all of the assets of the guarantors, except certain excluded assets, subject to liens securing parity lien debt and other permitted prior liens.

      The Company’s obligations pursuant to its guarantees of the performance, equity and indebtedness obligations were as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantee/ Maximum	 	 	 	Expiration	 	 	
 	 	Exposure	 	Nature of Guarantee	 	Date	 	Triggering Event	

	 	

	 	

	 	

	
 	 	(In thousands of dollars)	 	 	 	 	 	 	
Project/Subsidiary	 	 	 	 	 	 	 	 	 	 	 	 	
NRG Energy Second Priority Notes due 2013	 	$	1,753,000	 	 	Obligations under credit agreement	 	 	2013	 	 	Nonperformance	

 	Legal Issues	

 	Consolidated Edison Co. of New York v. Federal Energy Regulatory Commission, Docket No. 01-1503	
      Consolidated Edison and others petitioned the United States Court of Appeals for the District of Columbia Circuit for review of certain FERC orders in which FERC refused to order a redetermination of prices in the NYISO operating reserves markets for the period from January 29, 2000 to March 27, 2000. Petitioners alleged that the prices in the operating reserves markets were unduly elevated by approximately $65 million as a result of market power abuse and operating flaws. On November 7, 2003, the Court issued a decision which found that the NYISO’s method of pricing spinning reserves violated the NYISO tariff. The Court also required FERC to determine whether the exclusion of a generating facility known as Blenheim-Gilboa and resources located in western New York from the non-spinning market also constituted a tariff violation and/ or whether these exclusions enabled NYISO to use its Temporary Extraordinary Procedure authority to require refunds. It is unclear at this time whether FERC will require refunds, much less the amount of any such refunds. If refunds are required, NRG entities which may be affected include NRG Power Marketing, Inc., Astoria Gas Turbine Power LLC and Arthur Kill Power LLC. Although non-NRG-related entities will share responsibility for payment of such refunds, under the petitioners’ theory the cumulative exposure to our above-listed entities could, according to the NYISO, exceed $23 million.

 	Electricity Consumers Resource Council v. Federal Energy Regulatory Commission, Docket No. 03-1449	
      On December 19, 2003 the Electricity Consumers Resource Council (“ECRC”) appealed to the United States Court of Appeals for the District of Columbia Circuit a recent decision by FERC approving the implementation of a demand curve for the New York installed capacity (“ICAP”) market. ECRC claims that the implementation of the ICAP demand curve violates section 205 of the Federal Power Act because it constitutes unreasonable ratemaking. The Company is a party to this appeal and will contest ECRC’s assertions, but at this time cannot assess what the eventual outcome will be.

 	Connecticut Light & Power Company v. NRG Power Marketing Inc., Docket No. 3:01-CV-2373 (A WT), pending in the United States District Court, District of Connecticut	
      This matter involves a claim by Connecticut Light & Power Company for recovery of amounts allegedly owed for congestion charges under the terms of a Standard Offer Services contract between the parties, dated October 29, 1999. CL&P has served and filed its motion for summary judgment to which NRG Power

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NRG NORTHEAST GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Marketing, Inc. (“NRG Power Marketing”) filed a response on March 21, 2003. CL&P has withheld approximately $30 million from amounts owed to NRG Power Marketing, claiming that it has the right to offset those amounts under the contract. NRG Power Marketing has counterclaimed seeking to recover those amounts, arguing among other things that CL&P has no rights under the contract to offset them. By reason of the previous bankruptcy stay, the court has not ruled on the pending motion. On November 6, 2003, the parties filed a join stipulation for relief from the automatic stay in order to allow the proceeding to go forward, and NRG Power Marketing is about to supplement the record on the pending summary judgment motion. NRG Power Marketing cannot estimate at this time the likelihood of an unfavorable outcome in this matter.

 	The State of New York and Erin M. Crotty, as Commissioner of the New York State Department of Environmental Conservation v. Niagara Mohawk Power Corporation, NRG Energy, Inc., NRG Dunkirk Operations, Inc., Dunkirk Power, LLC, NRG Huntley Operations, Inc., Huntley Power, LLC, NRG Northeast Generating, LLC, Northeast Generation Holding, LLC, NRG Eastern, LLC and NRG Operating Services, Inc., United States District Court for the Western District of New York, Civil Action No. 02-CV-0024S	
      In January 2002, the New York Department of Environmental Conservation (“DEC”) sued Niagara Mohawk Power Corporation (“NiMo”), NRG Energy and certain of NRG Energy’s affiliates in federal court in New York. The complaint asserted that projects undertaken at NRG Energy’s Huntley and Dunkirk plants by NiMo, the former owner of the facilities, required preconstruction permits pursuant to the Clean Air Act and that the failure to obtain these permits violated federal and state laws. In July, 2002, the NRG entities filed a motion to dismiss. On March 27, 2003 the court dismissed the complaint against the NRG entities with prejudice as to the federal claims and without prejudice as to the state claims. On December 31, 2003, the trial court granted the state’s motion to amend the complaint to again sue NRG Energy and various affiliates in this same action in the federal court in New York, asserting against them violations of operating permits and deficient operating permits at the Huntley and Dunkirk plants. The parties have commenced written discovery, and the court has scheduled the trial on liability issues for March, 2006. For several months, the parties have been engaged in discussions respecting possible settlement of this matter. If the case ultimately is litigated to an unfavorable outcome that could not be addressed otherwise, NRG Energy has estimated that the total investment that would be required to install pollution control devices could be as high as $300 million over a ten to twelve-year period. The NRG entities also could be found responsible for payment of certain penalties and fines.

 	Niagara Mohawk Power Corporation v. NRG Energy, Inc., Huntley Power, LLC, and Dunkirk Power, LLC, Supreme Court, State of New York, County of Onondaga, Case No. 2001-4372	
      NRG Energy has asserted that NiMo is obligated to indemnify it for any related compliance costs associated with resolution of the above enforcement action. NiMo has filed suit in state court in New York seeking a declaratory judgment with respect to its obligations to indemnify NRG Energy under the asset sales agreement. NRG Energy has pending a summary judgment motion on its entitlement to be reimbursed by NIMO for attorneys’ fees incurred in the enforcement action.

 	Huntley Power LLC	
      On April 30, 2003, the Huntley Station submitted a self-disclosure letter to the DEC reporting violations of applicable sulfur in fuel limits, which had occurred during 6 days in March 2003 at the chimneystack serving Huntley Units 63-66. The Huntley Station self-disclosed that the average sulfur emissions rates for those days had been 1.8 lbs/mm BTU, rather that the maximum allowance of 1.7 lbs/mm BTU. NRG Huntley Operations discontinued use of Unit 65 (the only unit utilizing the subject stack at the time) and has kept the remaining three units off line until adherence with the applicable standard is assured. On May 19, 2003, the DEC issued Huntley Power LLC a Notice of Violation. Huntley Power LLC has met with the DEC

30

 
NRG NORTHEAST GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

to discuss the circumstances surrounding the event and the appropriate means of resolving the matter. Huntley Power LLC does not know what relief the DEC will seek through an enforcement action. Under applicable provisions of the Environmental Conservation Law, the DEC asserts that it may impose a civil penalty up to $10,000 plus an additional penalty not to exceed $10,000 for each day that a violation continues and may enjoin continuing violations.

 	Niagara Mohawk Power Corporation v. Dunkirk Power LLC, NRG Dunkirk Operations, Inc. Huntley Power LLC, Huntley Power Operations, Inc., Oswego Power LLC and Oswego Operations Inc., Supreme Court, Erie County, Index No. 1-2000-8681- Station Service Dispute	
      On October 2, 2000, plaintiff Niagara Mohawk Power Corporation commenced this action against NRG Energy to recover damages, plus late fees, less payments received, through the date of judgment, as well as any additional amounts due and owing for electric service provided to the Dunkirk Plant after September 18, 2000. Niagara Mohawk claims that NRG Energy has failed to pay retail tariff amounts for utility services commencing on or about June 11, 1999. Plaintiff has alleged breach of contract, suit on account, violation of statutory duty, and unjust enrichment claims. On or about October 23, 2000, NRG Energy served an answer denying liability and asserting affirmative defenses.

      After proceeding through discovery, and prior to trial, the parties and the court entered into a Stipulation and Order filed August 9, 2002, consolidating this action with two other actions against the Company’s Huntley and Oswego subsidiaries, both of which cases assert the same claims and legal theories for failure to pay retail tariffs for utility services at those plants.

      On October 8, 2002, a Stipulation and Order was filed in the Erie County Clerk’s Office staying this action, pending submission to FERC of some or all of these disputes. NRG Energy cannot make an evaluation of the likelihood of an unfavorable outcome. The cumulative potential loss could amount to some $40 million.

 	Niagara Mohawk Power Corporation V. Huntley Power LLC, NRG Huntley Operations, Inc., NRG Dunkirk Operations, Inc., Dunkirk Power LLC, Oswego Harbor Power LLC, and Oswego Operations, Inc., Case File November 26, 2002 in Federal Energy Regulatory Commission Docket No. EL 03-27-000	
      This is the companion action filed by NiMo at FERC, similarly asserting that NiMo is entitled to receive retail tariff amounts for electric service provided to the Huntley, Dunkirk and Oswego plants. On October 31, 2003, the FERC Trial Staff, a party to the proceedings, filed a reply brief in which it supported and agreed with each position taken by the Company’s facilities. In short, the staff argued that the Company’s facilities: (1) self-supply station power under the NYISO tariff (which took effect on April 1, 2003) in any month during which they produce more energy than they consume and, as such, should not be assessed a retail rate; (2) are connected only to transmission facilities and, as such, at most should only pay NiMo a FERC-approved transmission rate; and (3) should be allowed to net consumption and output even if power is injected into the grid at a different point from which it is drawn off. The Company is presently awaiting a ruling by FERC. At this stage of the proceeding, NRG Energy cannot estimate the likelihood of success on this action. As noted above, the cumulative potential loss could amount to some $40 million.

15.	Regulatory Issues	

 	New England	
      Effective March 1, 2003, ISO-NE implemented its version of standard market design (“SMD”). This change dramatically modifies the New England market structure by incorporating locational marginal pricing (“LMP” — pricing by location rather than on a New England wide basis). Even though NRG Northeast views this change as a significant improvement to the existing market design, NRG Northeast still views the market in New England as incapable of allowing NRG Northeast to recover its costs and provide a reasonable

31

 
NRG NORTHEAST GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

return on investment. Consequently, on February 26, 2003, Devon Power LLC, Middletown Power LLC, Montville Power LLC, Norwalk Power LLC and NRG Power Marketing (collectively, the “NRG Filers”) filed and requested a cost of service rate with the Federal Energy Regulatory Commission (“FERC”) for most of its Connecticut fleet, requesting a February 27th effective date. The NRG Filers remain committed to working with ISO-NE, FERC and other stakeholders to continue to improve the New England market that will hopefully make further reliance on a cost of service rate unnecessary. While the NRG Filers have the right to file for such rate treatment, there are no assurances that FERC will grant such rates in the form or amount that the NRG Filers petitioned for in their filing. On March 25, 2003, the FERC issued an order (the “Order”) in response to the NRG Filers’ Joint Motion for Emergency Expedited Issuance of Order by March 17, 2003, in Docket No. ER03-563-000 (the “Emergency Motion”). In the Emergency Motion, the NRG Filers requested that FERC accept the NRG Filers’ reliability must-run agreements and assure the NRG Filers’ recovery of deferred maintenance costs for their New England generating facilities prior to the peak summer season. FERC accepted the NRG Filers’ filing as to the recovery of spring 2003 maintenance costs, subject to refund. FERC’s Order authorizes the ISO New England Inc. to begin collecting these maintenance costs in escrow for the benefit of the NRG Filers as of February 27, 2003. Several intervenors protested the Emergency Motion. FERC did not rule on the remainder of the issues to allow further time to consider protests it received related to the filing.

      On April 25, 2003, FERC issued an order rejecting the remaining part of the proposed cost of service agreements including the monthly cost-based payment, citing certain policy determinations regarding cost of service agreements. Rather, FERC instructed ISO-NE to establish temporary bidding rules that would permit selected units (units with capacity factors of 10% or less during 2002), operating within designated congestion areas, such as Connecticut, to raise their bids to allow them the opportunity to recover their fixed and variable costs through the market. In May and June 2003, the ISO-NE revised its market rules to facilitate “peaking unit safe harbor,” or “PUSH,” bidding. On July 24, 2003, FERC clarified that the capacity factor of 10% or less applies to units rather than stations. Therefore, on a unit basis, all of the Company’s facilities qualify to bid under the temporary rules, except Middletown units 2 and 3. The PUSH bidding rule will remain in place until ISO-NE implements locational installed capacity payments, which FERC mandated ISO-NE implement no later than June 1, 2004. On March 1, 2004, ISO-NE filed a locational capacity proposal with FERC. Under the proposal, generators that are needed for reliability and have a capacity factor of 15% or less in 2003 are eligible for a monthly capacity payment of $5.38 per KW-month. Most of the Company’s generators located in Connecticut satisfy this requirement.

      Consistent with the Company’s expectations, PUSH bidding has not yielded sufficient revenues to cover all costs for most of the Company’s affected facilities. On January 16, 2004, the Company filed proposed reliability-must-run agreements, or “RMR agreements,” with FERC for the following facilities: Devon station units 11-14, Middletown station and Montville station. The RMR agreement filings requested FERC to establish cost of service rates. On March 18, 2004 FERC granted us a one date suspension of the rates, subject to refund, set the case for hearing and consolidated the case with other similar NRG Energy cases before a settlement judge. In the March 18, 2004 order the FERC ruled that the RMR agreements would expire with the implementation of a locational installed capacity (“LICAP”) market, which is expected to begin on June 1, 2004. On April 14, 2004 we filed a motion for rehearing with FERC requesting the FERC revise the termination date ruling. As of this date, FERC has not responded to the rehearing request.

      On February 6, 2004, we filed updated maintenance schedules for the tracking mechanism that provides for the payment by certain NEPOOL participants of third party maintenance expense incurred by NRG Energy. On April 1, 2004 FERC accepted the revised schedules, subject to refund, set the case for hearing and consolidated the case with other similar NRG Energy cases before a settlement judge. In the April 1, 2004 order the FERC ruled that the tracking mechanism would expire with the implementation of a locational installed capacity (“LICAP”) market, which is expected to begin on June 1, 2004. On April 14, 2004 we filed

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NRG NORTHEAST GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

a motion for rehearing with FERC requesting the FERC revise the termination date ruling. As of this date, FERC has not responded to the rehearing request.

      In addition to the facilities noted above, the following of the Company’s quick-start facilities in Connecticut have submitted PUSH bids that have been approved by FERC: Cos Cob, Franklin Drive, Branford, and Torrington. The existing RMR agreement between ISO-NE and the Company covering Devon station units 7 and 8 terminated on September 30, 2003. On October 2, 2003, the Company filed with FERC to extend the existing RMR agreement for the two Devon units. On December 1, 2003, FERC granted a one day suspension of the rates, subject to refund, set the case for hearing and appointed a settlement judge. On February 25, 2004, a FERC sponsored technical conference occurred to review the costs associated with the two Devon units. In the technical conference, the costs relevant to the RMR agreements were discussed. ISO NE has indicated in a letter dated February 27, 2004, that one of the Devon units will no longer be needed for reliability services. Therefore, on May 28, 2004, Devon 8 was retired. On May 28, 2004, a revised RMR Agreement was filed with FERC for Devon 7 facility to account for the cost remaining after the retirement of Devon 8. FERC has not yet acted on this revised RMR filing.

      On June 2, 2004, FERC rejected ISO-NE’s LICAP proposal. The FERC ruled that LICAP would not go into effect until January 1, 2006. Until the implementation of LICAP, the existing PUSH bidding rules and existing RMR Agreements would continue. New RMR Agreements must also end when the LICAP market is implemented. Under this ruling the RMR agreements noted above would not terminate on June 1, 2004 but both would terminate when LICAP is implemented on January 1, 2006 or until the facilities are no longer needed for reliability. In the order, FERC also requested ISO-NE to address the question of whether southwest Connecticut should be a separate zone for capacity and energy. Also, in the order, FERC requested an administrative law judge to hold an evidentiary hearing to determine specific components of the LICAP proposal.

      In response, ISO-NE, on July 7, 2004 filed a report with FERC requesting that a separate energy and capacity zone for southwest Connecticut be created effective as of January 1, 2006. Presently, there is only one energy and capacity zone for the entire state of Connecticut.

 	New York	
      In April 2003, the NYISO implemented a demand curve in its capacity market and scarcity pricing improvements in its energy market. The New York demand curve eliminated the previous market structure’s tendency to price capacity at either its cap (deficiency rate) or near zero. In a complaint filed with FERC on December 15, 2003, Consolidated Edison Company of New York, Inc. and other load-serving entities alleged that NYISO had used the wrong rate setting methodology to establish prices and rebates in the New York City markets for a portion of the summer capacity auction in 2003, and that this action resulted in overcharges to customers and overpayments to suppliers, including the Company, totaling approximately $21 million, with the Company’s share being approximately $5 million. If the complaint were granted, the Company may be required to refund payments. On December 19, 2003, the Electricity Consumers Resource Council appealed the FERC decision approving the demand curve in the United States Court of Appeals for the District of Columbia Circuit. If the appeal is granted, it could require the elimination of the demand curve for the capacity market. On February 11, 2004, a FERC sponsored settlement conference took place without successful resolution of the issue. The NYISO scarcity pricing improvements have re-introduced some volatility in the New York energy markets when supplies are short.

      The NYISO intends to introduce additional changes to its energy market in early 2004, with the implementation of Standard Market Design 2. Although the exact nature of these changes is not known at this time, the Company anticipates the changes to be small, targeted improvements to the NYISO’s present market.

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NRG NORTHEAST GENERATING LLC

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16.	Income Taxes (Restatement)	
      The Company is included in the consolidated tax return filings as a wholly owned indirect subsidiary of NRG Energy. Reflected in the financial statements and notes below are separate company federal and state tax provisions as if the Company had prepared separate filings. An income tax provision has been established on the accompanying consolidated financial statements as of the earliest period presented in order to reflect income taxes as if the Company filed its own tax return. The Company’s ultimate parent, NRG Energy, does not have a tax allocation agreement with its subsidiaries and prior to January 1, 2003, incomes taxes were not recorded or allocated to non tax paying entities or entities such as the Company which are treated as disregarded entities for tax purposes. Accordingly, the previously issued consolidated financial statements for the years ended December 31, 2002 and 2001, have been restated to include the effects of recording an income tax provision. Because the Company is not a party to a tax sharing agreement, current tax expense (benefit) is recorded as a capital contribution from (distribution to) the Company’s parent. The cumulative effect of recording an income tax provision (benefit) and deferred taxes resulted in recording as of December 31, 2000, a net deferred tax liability of $64.3 million and a reduction to members’ equity of $64.3 million.

      The provision (benefit) for income taxes consists of the following:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Current	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Federal	 	$	2,957	 	 	$	11,390	 	 	$	12,094	 	 	$	59,902	 	
 	State	 	 	1,183	 	 	 	4,555	 	 	 	4,837	 	 	 	23,959	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	4,140	 	 	 	15,945	 	 	 	16,931	 	 	 	83,861	 	
Deferred	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Federal	 	 	229	 	 	 	(89,837	)	 	 	(9,622	)	 	 	5,422	 	
 	State	 	 	91	 	 	 	(35,932	)	 	 	(3,849	)	 	 	2,168	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	320	 	 	 	(125,769	)	 	 	(13,471	)	 	 	7,590	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Total income tax expense (benefit)	 	$	4,460	 	 	$	(109,824	)	 	$	3,460	 	 	$	91,451	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Effective tax rate	 	 	43.2	%	 	 	43.0	%	 	 	89.1	%	 	 	43.3	%	
      The pre-tax income (loss) was as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
U.S. 	 	$	10,306	 	 	$	(255,511	)	 	$	3,885	 	 	$	211,255	 	
34

 
NRG NORTHEAST GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The components of the net deferred income tax (assets) liabilities were:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Deferred tax liabilities	 	 	 	 	 	 	 	 	 	 	 	 	
 	Property	 	$	—	 	 	$	—	 	 	$	77,192	 	
 	Investments in projects	 	 	3	 	 	 	3	 	 	 	1	 	
 	Development costs	 	 	—	 	 	 	—	 	 	 	2,555	 	
 	Emissions credits	 	 	90,722	 	 	 	90,722	 	 	 	—	 	
 	Other	 	 	1,982	 	 	 	1,691	 	 	 	7,030	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total deferred tax liabilities	 	 	92,707	 	 	 	92,416	 	 	 	86,778	 	
Deferred tax assets	 	 	 	 	 	 	 	 	 	 	 	 	
 	Deferred compensation, accrued vacation and other reserves	 	 	3,236	 	 	 	3,261	 	 	 	10,268	 	
 	Development costs	 	 	116	 	 	 	120	 	 	 	—	 	
 	Intangibles amortization (other than goodwill)	 	 	8,163	 	 	 	8,225	 	 	 	—	 	
 	Property	 	 	121,863	 	 	 	123,587	 	 	 	—	 	
 	Congestion accrual	 	 	48,035	 	 	 	47,811	 	 	 	—	 	
 	Other	 	 	2,406	 	 	 	844	 	 	 	18,113	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total deferred tax assets (before valuation allowance)	 	 	183,819	 	 	 	183,848	 	 	 	28,381	 	
Valuation allowance	 	 	—	 	 	 	—	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
Net deferred tax assets	 	 	183,819	 	 	 	183,848	 	 	 	28,381	 	

	 	 	 	

	 	 	 	

	 	
Net deferred tax (assets) liabilities	 	$	(91,112	)	 	$	(91,432	)	 	$	58,397	 	

	 	 	 	

	 	 	 	

	 	
      The net deferred tax (assets) liabilities consists of:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Current deferred tax liabilities (assets)	 	$	453	 	 	$	442	 	 	$	(9,709	)	
Noncurrent deferred tax (assets) liabilities	 	 	(91,565	)	 	 	(91,874	)	 	 	68,106	 	

	 	 	 	

	 	 	 	

	 	
Net deferred tax (assets) liabilities	 	$	(91,112	)	 	$	(91,432	)	 	$	58,397	 	

	 	 	 	

	 	 	 	

	 	
35

 
NRG NORTHEAST GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The effective income tax rates of continuing operations differ from the statutory federal income tax rate of 35% as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	 	 	 	 	
 	 	Company	 	 	 	Predecessor Company	 	 	

	 	 	 	

	 	 	
 	 	For the	 	 	 	For the	 	 	 	 	
 	 	Period from	 	 	 	Period from	 	 	 	 	 	 	
 	 	December 6,	 	 	 	January 1,	 	 	 	For the Years Ended	 	 	
 	 	2003 to	 	 	 	2003 to	 	 	 	December 31,	 	 	
 	 	December 31,	 	 	 	December 5,	 	 	 	

	 	 	
 	 	2003	 	 	 	2003	 	 	 	2002	 	 	 	2001	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	
 	 	 	
 	 	(In thousands of dollars)	
Income (loss) before taxes	 	$	10,306	 	 	 	 	 	 	$	(255,511	)	 	 	 	 	 	$	3,885	 	 	 	 	 	 	$	211,255	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	
Tax at 35%	 	 	3,607	 	 	 	35.0%	 	 	 	(89,429	)	 	 	35.0%	 	 	 	1,360	 	 	 	35.0%	 	 	 	73,939	 	 	 	35.0%	 	
State taxes (net of federal benefit)	 	 	828	 	 	 	8.0%	 	 	 	(20,395	)	 	 	8.0%	 	 	 	643	 	 	 	16.6%	 	 	 	16,983	 	 	 	8.0%	 	
Other	 	 	25	 	 	 	0.2%	 	 	 	—	 	 	 	0.0%	 	 	 	1,457	 	 	 	37.5%	 	 	 	529	 	 	 	0.3%	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	
Income tax expense (benefit)	 	$	4,460	 	 	 	43.2%	 	 	$	(109,824	)	 	 	43.0%	 	 	$	3,460	 	 	 	89.1%	 	 	$	91,451	 	 	 	43.3%	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	

17.	Reorganization Cash Payments and Receipts	

 	Cash Payments	

 	Professional Fees	
      During the period from May 14, 2003 to December 5, 2003 and the period from December 6, 2003 to December 31, 2003, the Company made cash payments for professional fees to financial and legal advisors of $1.3 million and $0.2 million, respectively.

 	Refinancing Activities	
      The Company made cash payments of $556.6 million related to the repayment of debt, including accrued interest of $1.1 million upon the emergence from bankruptcy on December 23, 2003, with proceeds from NRG Energy’s recently completed corporate level refinancing. The Company also made cash payments of $8.3 million for a pre-payment settlement upon the early payment of the debt.

 	Creditor Payments	
      Upon the Company’s emergence from bankruptcy, no cash payments were made to creditors during the period from December 6, 2003 to December 31, 2003.

36

 

REPORT OF INDEPENDENT AUDITORS ON
FINANCIAL STATEMENT SCHEDULE

To the Members of
NRG Northeast Generating LLC:

      Our audits of the consolidated financial statements referred to in our report dated March 10, 2004, also included an audit of the financial statement schedule listed herein. In our opinion, this financial statement schedule for the period from January 1, 2003 to December 5, 2003 and for the two years ended December 31, 2002, presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
 	 	
 	/s/ PRICEWATERHOUSECOOPERS LLP	

	
 	PricewaterhouseCoopers LLP	
Minneapolis, Minnesota
March 10, 2004

37

 

REPORT OF INDEPENDENT AUDITORS ON
FINANCIAL STATEMENT SCHEDULE

To the Members of
NRG Northeast Generating LLC:

      Our audits of the consolidated financial statements referred to in our report dated March 10, 2004, also included an audit of the financial statement schedule listed herein. In our opinion, this financial statement schedule for the period from December 6, 2003 to December 31, 2003 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
 	 	
 	/s/ PRICEWATERHOUSECOOPERS LLP	

	
 	PricewaterhouseCoopers LLP	
Minneapolis, Minnesota
March 10, 2004

38

 

NRG NORTHEAST GENERATING LLC

SCHEDULE II. VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2003, 2002 and 2001

Column A	 	Column B	 	Column C	 	Column D	 	Column E	

	 	

	 	

	 	

	 	

	
 	 	 	 	 	 	 	 	 	
 	 	 	 	Additions	 	 	 	 	

	 	 	 	 	
 	 	Balance at	 	Charged to	 	Charged to	 	 	 	Balance at	
 	 	Beginning	 	Costs and	 	Other	 	 	 	End of	
Description	 	of Period	 	Expenses	 	Accounts	 	Deductions	 	Period	

	 	

	 	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands)	
Allowance for doubtful accounts, deducted from accounts receivable in the balance sheet:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Predecessor Company	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Year ended December 31, 2001	 	$	8,165	 	 	$	(8,165	)	 	$	—	 	 	$	—	 	 	$	—	 	
Year ended December 31, 2002	 	 	—	 	 	 	50,712	 	 	 	—	 	 	 	—	 	 	 	50,712	 	
January 1 - December 5, 2003	 	 	50,712	 	 	 	—	 	 	 	—	 	 	 	(50,712	)	 	 	—	 	

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reorganized Company	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
December 6 - December 31, 2003	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
39

 

EXHIBIT 99.4

INDIAN RIVER POWER LLC

FINANCIAL STATEMENTS

At December 31, 2003, December 6, 2003 and
December 31, 2002, and for the Period from
December 6, 2003 to December 31, 2003, the Period
from January 1, 2003 to December 5, 2003 and for
the Years Ended December 31, 2002 and 2001

 

INDIAN RIVER POWER LLC

INDEX
 	 	 	 	 	
 	 	Page(s)	

	
Reports of Independent Auditors	 	 	2-3	 	
Financial Statements	 	 	 	 	
Balance Sheets at December 31, 2003, December 6, 2003 and December 31, 2002	 	 	4	 	
Statements of Operations for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001	 	 	5	 	
Statements of Member’s Equity for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001	 	 	6	 	
Statements of Cash Flows for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001	 	 	7	 	
Notes to Financial Statements	 	 	8-22	 	
1

 

REPORT OF INDEPENDENT AUDITORS

To the Member of
Indian River Power LLC

      In our opinion, the accompanying balance sheet and the related statements of operations, of member’s equity, and of cash flows present fairly, in all material respects, the financial position of Indian River Power LLC (“Predecessor Company”) at December 31, 2002, and the results of its operations and its cash flows for the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      As discussed in Note 1 to the financial statements, the Company’s ultimate parent, NRG Energy, Inc., filed a petition on May 14, 2003, with the United States Bankruptcy Court for the Southern District of New York for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. NRG Energy, Inc.’s Plan of Reorganization was substantially consummated on December 5, 2003, and Reorganized NRG emerged from bankruptcy. The impact of NRG Energy, Inc.’s emergence from bankruptcy and fresh start accounting was applied to the Company on December 5, 2003 under push down accounting methodology.
 	 	
 	/s/ PRICEWATERHOUSECOOPERS LLP	

	
 	PricewaterhouseCoopers LLP	
Minneapolis, Minnesota
March 10, 2004

2

 

REPORT OF INDEPENDENT AUDITORS

To the Member of
Indian River Power LLC

      In our opinion, the accompanying balance sheets and the related statements of operations, of member’s equity, and of cash flows present fairly, in all material respects, the financial position of Indian River Power LLC (“Reorganized Company”) at December 31, 2003 and December 6, 2003, and the results of its operations and its cash flows for the period from December 6, 2003 to December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      As discussed in Note 1 to the financial statements, the United States Bankruptcy Court for the Southern District of New York confirmed the NRG Energy, Inc., the Company’s ultimate parent, Plan of Reorganization on November 24, 2003. The NRG Energy, Inc. Plan of Reorganization was substantially consummated on December 5, 2003, and NRG Energy, Inc. emerged from bankruptcy. The impact of NRG Energy, Inc.’s emergence from bankruptcy and fresh start accounting was applied to the Company on December 5, 2003 under push down accounting methodology.
 	 	
 	/s/ PRICEWATERHOUSECOOPERS LLP	

	
 	PricewaterhouseCoopers LLP	
Minneapolis, Minnesota
March 10, 2004

3

 

INDIAN RIVER POWER LLC

BALANCE SHEETS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
ASSETS	
Current assets	 	 	 	 	 	 	 	 	 	 	 	 	
 	Accounts receivable	 	$	—	 	 	$	—	 	 	$	10,550	 	
 	Accounts receivable — affiliates	 	 	—	 	 	 	3,736	 	 	 	—	 	
 	Inventory	 	 	13,702	 	 	 	11,400	 	 	 	20,474	 	
 	Prepayments and other current assets	 	 	1,171	 	 	 	1,364	 	 	 	8,883	 	
 	Current deferred income tax	 	 	—	 	 	 	—	 	 	 	117	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total current assets	 	 	14,873	 	 	 	16,500	 	 	 	40,024	 	
Property, plant and equipment, net of accumulated depreciation of $1,080, $0 and $34,445, respectively	 	 	395,021	 	 	 	395,000	 	 	 	663,281	 	
Debt issuance costs, net of accumulated amortization of $0, $0 and $2,005, respectively	 	 	—	 	 	 	—	 	 	 	4,676	 	
Intangible assets	 	 	57,531	 	 	 	57,531	 	 	 	—	 	
Other assets	 	 	6,668	 	 	 	6,663	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total assets	 	$	474,093	 	 	$	475,694	 	 	$	707,981	 	

	 	 	 	

	 	 	 	

	 	
 	
LIABILITIES AND MEMBER’S EQUITY	
Current liabilities	 	 	 	 	 	 	 	 	 	 	 	 	
 	Current portion of long-term debt	 	$	—	 	 	$	310,986	 	 	$	312,993	 	
 	Bank overdraft	 	 	—	 	 	 	—	 	 	 	1,028	 	
 	Accounts payable — trade	 	 	3	 	 	 	3	 	 	 	—	 	
 	Accounts payable — affiliates	 	 	59,734	 	 	 	—	 	 	 	14,901	 	
 	Accrued interest	 	 	—	 	 	 	2,497	 	 	 	40	 	
 	Accrued expenses	 	 	142	 	 	 	136	 	 	 	1,721	 	
 	Current deferred income tax	 	 	44	 	 	 	44	 	 	 	—	 	
 	Other current liabilities	 	 	40	 	 	 	—	 	 	 	141	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total current liabilities	 	 	59,963	 	 	 	313,666	 	 	 	330,824	 	
Deferred income tax	 	 	15,144	 	 	 	16,222	 	 	 	98,995	 	
Other long-term obligations	 	 	4,256	 	 	 	4,232	 	 	 	82	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total liabilities	 	 	79,363	 	 	 	334,120	 	 	 	429,901	 	

	 	 	 	

	 	 	 	

	 	
Commitments and contingencies	 	 	 	 	 	 	 	 	 	 	 	 	
Member’s equity	 	 	394,730	 	 	 	141,574	 	 	 	278,080	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total liabilities and member’s equity	 	$	474,093	 	 	$	475,694	 	 	$	707,981	 	

	 	 	 	

	 	 	 	

	 	
The accompanying notes are an integral part of these financial statements.

4

 

INDIAN RIVER POWER LLC

STATEMENTS OF OPERATIONS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Revenues	 	$	4,925	 	 	$	136,361	 	 	$	200,170	 	 	$	102,946	 	
Operating costs	 	 	4,882	 	 	 	90,717	 	 	 	76,265	 	 	 	30,043	 	
Depreciation	 	 	1,080	 	 	 	22,972	 	 	 	23,097	 	 	 	11,734	 	
General and administrative expenses	 	 	942	 	 	 	1,872	 	 	 	2,242	 	 	 	1,127	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	(Loss) income from operations	 	 	(1,979	)	 	 	20,800	 	 	 	98,566	 	 	 	60,042	 	
Interest expense	 	 	(667	)	 	 	(14,303	)	 	 	(10,830	)	 	 	(6,522	)	
Other income, net	 	 	6	 	 	 	143	 	 	 	90	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	(Loss) income before income taxes	 	 	(2,640	)	 	 	6,640	 	 	 	87,826	 	 	 	53,520	 	
Income tax (benefit) expense	 	 	(1,078	)	 	 	2,712	 	 	 	34,926	 	 	 	21,863	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	Net (loss) income	 	$	(1,562	)	 	$	3,928	 	 	$	52,900	 	 	$	31,657	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
The accompanying notes are an integral part of these financial statements.

5

 

INDIAN RIVER POWER LLC

STATEMENTS OF MEMBER’S EQUITY

 	 	Member	 	Member	 	Accumulated	 	Total	

	 	Contributions/	 	Net Income	 	Member’s	
 	 	Units	 	Amount	 	Distributions	 	(Loss)	 	Equity	

	 	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Balances at December 31, 2000	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	(Predecessor Company)	 	 	—	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	
Contribution from member	 	 	1,000	 	 	 	1	 	 	 	192,300	 	 	 	—	 	 	 	192,301	 	
Net income	 	 	—	 	 	 	—	 	 	 	—	 	 	 	31,657	 	 	 	31,657	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Balances at December 31, 2001	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	(Predecessor Company)	 	 	1,000	 	 	 	1	 	 	 	192,300	 	 	 	31,657	 	 	 	223,958	 	
Contribution from member	 	 	—	 	 	 	—	 	 	 	1,222	 	 	 	—	 	 	 	1,222	 	
Net income	 	 	—	 	 	 	—	 	 	 	—	 	 	 	52,900	 	 	 	52,900	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Balances at December 31, 2002	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	(Predecessor Company)	 	 	1,000	 	 	 	1	 	 	 	193,522	 	 	 	84,557	 	 	 	278,080	 	
Net income	 	 	—	 	 	 	—	 	 	 	—	 	 	 	3,928	 	 	 	3,928	 	
Distribution to member	 	 	—	 	 	 	—	 	 	 	(16,971	)	 	 	—	 	 	 	(16,971	)	
Balances at December 5, 2003	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	(Predecessor Company)	 	 	1,000	 	 	 	1	 	 	 	176,551	 	 	 	88,485	 	 	 	265,037	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Push down accounting adjustment	 	 	—	 	 	 	—	 	 	 	(34,978	)	 	 	(88,485	)	 	 	(123,463	)	
Balances at December 6, 2003	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	(Reorganized Company)	 	 	1,000	 	 	 	1	 	 	 	141,573	 	 	 	—	 	 	 	141,574	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Contribution from member	 	 	—	 	 	 	—	 	 	 	254,718	 	 	 	—	 	 	 	254,718	 	
Net loss	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(1,562	)	 	 	(1,562	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Balances at December 31, 2003	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	(Reorganized Company)	 	 	1,000	 	 	$	1	 	 	$	396,291	 	 	$	(1,562	)	 	$	394,730	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
The accompanying notes are an integral part of these financial statements.

6

 

INDIAN RIVER POWER LLC

STATEMENTS OF CASH FLOWS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Cash flows from operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net (loss) income	 	$	(1,562	)	 	$	3,928	 	 	$	52,900	 	 	$	31,657	 	
Adjustments to reconcile net (loss) income to net cash provided by operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Depreciation	 	 	1,080	 	 	 	22,972	 	 	 	23,097	 	 	 	11,734	 	
 	Amortization of debt issuance costs	 	 	—	 	 	 	1,243	 	 	 	1,815	 	 	 	190	 	
 	Amortization of out-of-market contracts	 	 	—	 	 	 	—	 	 	 	(89,251	)	 	 	(54,963	)	
 	Deferred income taxes	 	 	(1,078	)	 	 	2,712	 	 	 	34,926	 	 	 	17,985	 	
 	Current tax expense — noncash contribution from member	 	 	—	 	 	 	—	 	 	 	—	 	 	 	3,878	 	
 	Changes in assets and liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Accounts receivable	 	 	—	 	 	 	10,550	 	 	 	(1,977	)	 	 	(8,573	)	
 	 	Accounts receivable — affiliates	 	 	3,736	 	 	 	(3,736	)	 	 	—	 	 	 	—	 	
 	 	Inventory	 	 	(2,302	)	 	 	7,099	 	 	 	3,082	 	 	 	(5,158	)	
 	 	Prepayments and other current assets	 	 	193	 	 	 	7,519	 	 	 	(7,965	)	 	 	(918	)	
 	 	Other assets	 	 	(5	)	 	 	(6,663	)	 	 	—	 	 	 	—	 	
 	 	Accounts payable — trade	 	 	—	 	 	 	3	 	 	 	—	 	 	 	—	 	
 	 	Accounts payable — affiliates	 	 	59,734	 	 	 	(14,901	)	 	 	(873	)	 	 	17,516	 	
 	 	Accrued interest	 	 	(2,497	)	 	 	2,457	 	 	 	(1,966	)	 	 	2,007	 	
 	 	Changes in other assets and liabilities	 	 	70	 	 	 	(1,222	)	 	 	(6,771	)	 	 	1,770	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	Net cash provided by operating activities	 	 	57,369	 	 	 	31,961	 	 	 	7,017	 	 	 	17,125	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Cash flows from investing activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Acquisition, net of liabilities assumed	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(514,163	)	
Capital expenditures	 	 	(1,101	)	 	 	(11,955	)	 	 	(4,917	)	 	 	(10,704	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	Net cash used in investing activities	 	 	(1,101	)	 	 	(11,955	)	 	 	(4,917	)	 	 	(524,867	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Cash flows from financing activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Bank overdraft	 	 	—	 	 	 	(1,028	)	 	 	1,028	 	 	 	—	 	
Debt issuance costs	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(1,901	)	
Payments on debt	 	 	(310,986	)	 	 	(2,007	)	 	 	(4,350	)	 	 	—	 	
Proceeds from debt issuance	 	 	—	 	 	 	—	 	 	 	—	 	 	 	317,343	 	
Contribution from member	 	 	254,718	 	 	 	—	 	 	 	1,222	 	 	 	192,300	 	
Distribution to member	 	 	—	 	 	 	(16,971	)	 	 	—	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	Net cash (used in) provided by financing activities	 	 	(56,268	)	 	 	(20,006	)	 	 	(2,100	)	 	 	507,742	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	Net change in cash and cash equivalents	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Cash and cash equivalents	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Beginning of period	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
End of period	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Supplemental disclosures of cash flow information	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash paid for interest	 	$	3,132	 	 	$	10,603	 	 	$	14,375	 	 	$	6,857	 	
Noncash contribution for current tax expense from member	 	 	—	 	 	 	—	 	 	 	—	 	 	 	3,878	 	
Detail of assets acquired	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current assets	 	$	—	 	 	$	—	 	 	$	—	 	 	$	18,398	 	
Fair value of noncurrent assets	 	 	—	 	 	 	—	 	 	 	—	 	 	 	689,014	 	
Liabilities assumed	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(193,249	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Cash paid	 	$	—	 	 	$	—	 	 	$	—	 	 	$	514,163	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
The accompanying notes are an integral part of these financial statements.

7

 

INDIAN RIVER POWER LLC

NOTES TO FINANCIAL STATEMENTS

1.     Organization

      Indian River Power LLC (the “Company”) is an indirect wholly owned subsidiary of NRG Energy, Inc. (“NRG Energy”). NRG Mid Atlantic Generating LLC (“Mid Atlantic Gen”) owns 100% of the Company. Mid Atlantic Gen’s members are Mid Atlantic Generation Holding LLC and NRG Mid Atlantic LLC, both of which are wholly owned subsidiaries of NRG Energy and each of which owns a 50% interest in Mid Atlantic Gen.

     Recent Developments

      On May 14, 2003, NRG Energy and 25 of its direct and indirect wholly owned subsidiaries commenced voluntary petitions under Chapter 11 of the bankruptcy code in the United States Bankruptcy Court for the Southern District of New York. During the bankruptcy proceedings, NRG Energy continued to conduct business and manage the companies as debtors in possession pursuant to sections 1107(a) and 1108 of the bankruptcy code. The Company was not part of these Chapter 11 cases or any of the subsequent bankruptcy filings. On November 24, 2003, the bankruptcy court entered an order confirming NRG Energy’s Plan of Reorganization and the plan became effective on December 5, 2003. In connection with NRG Energy’s emergence from bankruptcy, NRG Energy adopted fresh start accounting in accordance with AICPA Statement of Position 90-7, Financial Reporting by Entities in Reorganization Under the Bankruptcy Code  (“SOP 90-7”) on December 5, 2003. NRG Energy’s fresh start accounting was applied to the Company on a push down accounting basis with the financial statement impact recorded as an adjustment to the December 6, 2003, member’s equity in the amount of $123.5 million.

     NRG Energy’s Plan of Reorganization

      NRG Energy’s Plan of Reorganization is the result of several months of intense negotiations among NRG Energy, Xcel Energy, Inc. (“Xcel Energy”) and the two principal committees representing NRG Energy creditor groups, referred to as the Global Steering Committee and the Noteholder Committee. A principal component of NRG Energy’s Plan of Reorganization is a settlement with Xcel Energy in which Xcel Energy agreed to make a contribution consisting of cash (and, under certain circumstances, its stock) in the aggregate amount of up to $640 million to be paid in three separate installments following the effective date of NRG Energy’s Plan of Reorganization. The Xcel Energy settlement agreement resolves any and all claims existing between Xcel Energy and NRG Energy and/or its creditors and, in exchange for the Xcel Energy contribution, Xcel Energy is receiving a complete release of claims from NRG Energy and its creditors, except for a limited number of creditors who have preserved their claims as set forth in the confirmation order entered on November 24, 2003.

2.	Summary of Significant Accounting Policies	

 	NRG Energy Fresh Start Reporting/ Push Down Accounting	
      In accordance with SOP 90-7, certain companies qualify for fresh start (“Fresh Start”) reporting in connection with their emergence from bankruptcy. Fresh Start reporting is appropriate on the emergence from Chapter 11 if the reorganization value of the assets of the emerging entity immediately before the date of confirmation is less than the total of all post-petition liabilities and allowed claims, and if the holders of existing voting shares immediately before confirmation receive less than 50% of the voting shares of the emerging entity. NRG Energy met these requirements and adopted Fresh Start reporting and applied push down accounting to its various subsidiary operations including the Company. Under push down accounting, the Company’s equity fair value was allocated to the Company’s assets and liabilities based on their estimated fair values as of December 5, 2003, as further described in Note 3.

8

 
INDIAN RIVER POWER LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

      Under the requirements of Fresh Start, NRG Energy adjusted its assets and liabilities, other than deferred income taxes, to their estimated fair values as of December 5, 2003. As a result of marking the assets and liabilities to their estimated fair values, NRG Energy determined that there was a negative reorganization value that was reallocated back to the tangible and intangible assets. Deferred taxes were determined in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 109,  Accounting for Income Taxes . The net effect of all Fresh Start adjustments resulted in a gain of $3.9 billion, which is reflected in NRG Energy’s Predecessor Company results for the period from January 1, 2003 to December 5, 2003. The application of the Fresh Start provisions of SOP 90-7 created a new reporting entity having no retained earnings or accumulated deficit.

      As part of the bankruptcy process, NRG Energy engaged an independent financial advisor to assist in the determination of its reorganized enterprise value. The fair value calculation was based on management’s forecast of expected cash flows from its core assets. Management’s forecast incorporated forward commodity market prices obtained from a third party consulting firm. A discounted cash flow calculation was used to develop the enterprise value of Reorganized NRG, determined in part by calculating the weighted average cost of capital of the Reorganized NRG. The Discounted Cash Flow, (“DCF,”) valuation methodology equates the value of an asset or business to the present value of expected future economic benefits to be generated by that asset or business. The DCF methodology is a “forward looking” approach that discounts expected future economic benefits by a theoretical or observed discount rate. The independent financial advisor prepared a 30-year cash flow forecast using a discount rate of approximately 11%. The resulting reorganization enterprise value as included in the Disclosure Statement ranged from $5.5 billion to $5.7 billion. The independent financial advisor then subtracted NRG Energy’s project level debt and made several other adjustments to reflect the values of assets held for sale, excess cash and collateral requirements to estimate a range of Reorganized NRG equity value of between $2.2 billion and $2.6 billion.

      In constructing the Fresh Start balance sheet upon emergence from bankruptcy, NRG Energy used a reorganization equity value of approximately $2.4 billion, as NRG Energy believed this value to be the best indication of the value of the ownership distributed to the new equity owners. NRG Energy’s Plan of Reorganization provided for the issuance of 100,000,000 shares of NRG Energy common stock to the various creditors resulting in a calculated price per share of $24.04. The reorganization value of approximately $9.1 billion was determined by adding the reorganized equity value of $2.4 billion, $3.7 billion of interest bearing debt and other liabilities of $3.0 billion. The reorganization value represents the fair value of an entity before liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after restructuring. This value is consistent with the voting creditors and Court’s approval of NRG Energy’s Plan of Reorganization.

      The application of SOP 90-7 and push down accounting resulted in the creation of a new reporting entity for the Company. Consequently, the financial statements of the Reorganized Company and the Predecessor Company are separated by a black line to distinguish that the assets, liabilities and member’s equity as well as the results of operations are not comparable between periods. Under the requirements of push down accounting, the Company has adjusted its assets and liabilities to their estimated fair values as of December 5, 2003. The impact of pushdown accounting resulted in the reduction of member’s equity for the Company in the amount of $123.5 million.

9

 
INDIAN RIVER POWER LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

      For financial reporting purposes, close of business on December 5, 2003, represents the date of NRG Energy’s emergence from bankruptcy. As used herein, the following terms refer to the Company and its operations:
 	 	 	
“Predecessor Company”	 	The Company, prior to push down accounting
The Company’s operations, January 1, 2001 - December 31, 2001
The Company’s operations, January 1, 2002 - December 31, 2002
The Company’s operations, January 1, 2003 - December 5, 2003	
 	
“Reorganized Company”	 	The Company, post push down accounting
The Company’s operations, December 6, 2003 - December 31, 2003	
      The bankruptcy court in its confirmation order approved NRG Energy’s Plan of Reorganization on November 24, 2003. Under the requirements of SOP 90-7, the Fresh Start date is determined to be the confirmation date unless significant uncertainties exist regarding the effectiveness of the bankruptcy order. NRG Energy’s Plan of Reorganization required completion of the Xcel Energy settlement agreement prior to emergence from bankruptcy. Management believes this settlement agreement was a significant contingency and thus delayed the Fresh Start date until the Xcel Energy settlement agreement was finalized on December 5, 2003.

     Inventory

      Inventory consists of fuel oil, spare parts and coal and is valued at the lower of weighted average cost or market.

     Property, Plant and Equipment

      The Company’s property, plant and equipment are stated at cost; however, impairment adjustments are recorded whenever events or changes in circumstances indicate carrying values may not be recoverable. At December 5, 2003, the Company recorded adjustments to the property, plant and equipment to reflect such items at fair value in accordance with push down accounting. A new cost basis was established with these adjustments. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance that do not improve or extend the life of the respective asset, are charged to expense as incurred. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets. The assets and related accumulated depreciation amounts are adjusted for asset retirements and disposals, with the resulting gain or loss included in operations.

     Asset Impairment

      Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate carrying values may not be recoverable. Such reviews are performed in accordance with SFAS No. 144,  Accounting for the Impairment or Disposal of Long-lived Assets . An impairment loss is recognized if the total future estimated undiscounted cash flows expected from an asset are less than its carrying value. An impairment charge is measured by the difference between an asset’s carrying amount and fair value. Fair values are determined by a variety of valuation methods, including appraisals, sales prices of similar assets and present value techniques.

     Debt Issuance Costs

      Debt issuance costs consist of legal and other costs incurred to obtain debt financing. These costs, which were written off as part of pushdown accounting (see Note 3), were being amortized as interest expense on a basis which approximates the effective interest method over the terms of the related debt.

10

 
INDIAN RIVER POWER LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

     Intangible Assets

      Intangible assets represent contractual rights held by the Company. Intangible assets are amortized over their economic useful life and reviewed for impairment on a periodic basis. Nonamortized intangible assets, including goodwill, are tested for impairment annually and on an interim basis if an event or circumstance occurs between annual tests that might reduce the fair value of that asset.

      Intangible assets consists of the fair value of emission allowances. Emission allowance related amounts will be amortized as additional fuel expense based upon the actual level of emissions from the respective plant through 2023.

      Effective January 1, 2002, the Company implemented SFAS No. 142, Goodwill and Other Intangible Assets. Pursuant to SFAS No. 142, goodwill is not amortized but is subject to periodic testing. At December 31, 2003, December 6, 2003 and December 31, 2002, the Company had no goodwill recorded in the financial statements.

     Fair Value of Financial Instruments

      The carrying amount of accounts receivable, accounts payable and accrued liabilities approximate fair value because of the short maturity of these instruments. The carrying amount of long-term debt approximates fair value due to the variable rate of interest associated with the long-term debt.

     Income Taxes

      The Company has been organized as a limited liability company. Therefore, federal and state income taxes are assessed at the member level. However, a provision for separate company federal and state income taxes has been reflected in the accompanying financial statements (see Note 14 — Income Taxes). As a result of the Company being included in the NRG Energy consolidated tax return and tax payments, federal and state taxes payable amounts resulting from the tax provision are reflected as a contribution by member in the statement of member’s equity and balance sheet.

      Deferred income taxes are recognized for the tax consequences in future years of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts at each year end based on enacted tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. Income tax expense is the tax payable for the period and the change during the period in deferred tax assets and liabilities. A valuation allowance is recorded to reduce deferred tax assets to the amount more likely than not to be realized.

     Comprehensive Income

      For all periods, net income is equal to comprehensive income as there were no additional items impacting comprehensive income for each of the periods presented.

     Revenue Recognition

      Revenues are recorded based on capacity provided and electrical output delivered at the lesser of amounts billable under the power purchase agreements, or the average estimated contract rates over the initial term of the contracts.

      In certain markets which are operated/controlled by an independent system operator (“ISO”) and in which the Company has entered into a netting agreement with the ISO, which results in the Company receiving a netted invoice, the Company records purchased energy as an offset against revenues received upon the sale of such energy. Disputed revenues are not recorded in the financial statements until disputes are resolved and collection is assured.

11

 
INDIAN RIVER POWER LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

     Power Marketing Activities

      The Company has entered into an agency agreement with a marketing affiliate for the sale of energy, capacity and ancillary services produced and for the procurement and management of fuel and emissions credit allowances, which enables the affiliate to engage in forward sales and economic hedges to manage the Company’s electricity price exposure. Net gains or losses on hedges by the affiliate, which are physically settled, are recognized in the same manner as the hedged item. The Company receives the net transaction price on all contracts that are physically settled by its marketing affiliate.

     Concentrations of Credit Risk

      Financial instruments, which potentially subject the Company to concentrations of credit risk, consist primarily of accounts receivable and investments in debt securities. Accounts receivable and derivative instruments are concentrated within entities engaged in the energy industry. These industry concentrations may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. Receivables are generally not collateralized; however, the Company believes the credit risk posed by industry concentration is offset by the diversification and credit worthiness of its customer base.

     Use of Estimates in Financial Statements

      The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenue and expenses during the reporting period. Actual results may differ from those estimates.

      In recording transactions and balances resulting from business operations, the Company uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, uncollectible accounts and the valuation of long-term energy commodities contracts, among others. In addition, estimates are used to test long-lived assets for impairment and to determine fair value of impaired assets. As better information becomes available (or actual amounts are determinable), the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

3.	Emergence from Bankruptcy and Fresh Start Reporting	
      In accordance with the requirements of pushdown accounting, the Company’s fair value of $141.6 million was allocated to the Company’s assets and liabilities based on their individual estimated fair values. A third party was used to complete an independent appraisal of the Company’s tangible assets, intangible assets and contracts.

      The determination of the fair value of the Company’s assets and liabilities was based on a number of estimates and assumptions, which are inherently subject to significant uncertainties and contingencies.

      Due to the adoption of push down accounting as of December 5, 2003, the Reorganized Company’s balance sheets, statements of operations and cash flows have not been prepared on a consistent basis with the Predecessor Company’s financial statements and are not comparable in certain respects to the financial statements prior to the application of push down accounting. A black line has been drawn on the accompanying financial statements to separate and distinguish between the Reorganized Company and the

12

 
INDIAN RIVER POWER LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

Predecessor Company. The effects of the push down accounting adjustments on the Company’s balance sheet as of December 5, 2003, were as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor	 	 	 	Reorganized	
 	 	Company	 	 	 	Company	

	 	 	 	

	
 	 	December 5,	 	Push Down	 	December 6,	
 	 	2003	 	Adjustments	 	2003	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
ASSETS	
Current assets	 	 	 	 	 	 	 	 	 	 	 	 	
 	Accounts receivable — affiliates	 	$	3,736	 	 	$	—	 	 	$	3,736	 	
 	Inventory	 	 	13,375	 	 	 	(1,975	)(A)	 	 	11,400	 	
 	Prepayments and other current assets	 	 	1,364	 	 	 	—	 	 	 	1,364	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total current assets	 	 	18,475	 	 	 	(1,975	)	 	 	16,500	 	
Property, plant and equipment, net	 	 	653,794	 	 	 	(258,794	)(B)	 	 	395,000	 	
Debt issuance costs, net	 	 	3,433	 	 	 	(3,433	)(C)	 	 	—	 	
Intangible assets	 	 	—	 	 	 	57,531	 (D)	 	 	57,531	 	
Other assets	 	 	6,663	 	 	 	—	 	 	 	6,663	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total assets	 	$	682,365	 	 	$	(206,671	)	 	$	475,694	 	

	 	 	 	

	 	 	 	

	 	
 	
LIABILITIES AND MEMBER’S EQUITY	
Current liabilities	 	 	 	 	 	 	 	 	 	 	 	 	
 	Current portion of long-term debt	 	$	310,986	 	 	$	—	 	 	$	310,986	 	
 	Accounts payable — trade	 	 	3	 	 	 	—	 	 	 	3	 	
 	Accrued interest	 	 	2,497	 	 	 	—	 	 	 	2,497	 	
 	Accrued expenses	 	 	136	 	 	 	—	 	 	 	136	 	
 	Current deferred income tax	 	 	—	 	 	 	44	(E)	 	 	44	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total current liabilities	 	 	313,622	 	 	 	44	 	 	 	313,666	 	
Deferred income tax	 	 	101,707	 	 	 	(85,485	)(E)	 	 	16,222	 	
Other long-term obligations	 	 	1,999	 	 	 	2,233	 (F)	 	 	4,232	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total liabilities	 	 	417,328	 	 	 	(83,208	)	 	 	334,120	 	

	 	 	 	

	 	 	 	

	 	
Member’s equity	 	 	 	 	 	 	 	 	 	 	 	 	
 	Member’s contributions	 	 	176,552	 	 	 	(34,978	)	 	 	141,574	 	
 	Accumulated net income	 	 	88,485	 	 	 	(88,485	)	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total member’s equity	 	 	265,037	 	 	 	(123,463	)(G)	 	 	141,574	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total liabilities and member’s equity	 	$	682,365	 	 	$	(206,671	)	 	$	475,694	 	

	 	 	 	

	 	 	 	

	 	

 
 	 	 	
(A)	 	Accounting policy change upon adoption of push down accounting. Consumables are no longer included as inventory and are expensed as incurred. Capital spare parts were reclassified from inventory to property, plant and equipment.	
 	 	 	
(B)	 	Result of allocating the Company’s equity value in conformity with the purchase method of accounting for business combinations. These allocations were based on valuations obtained from independent appraisers.	
 	 	 	
(C)	 	Revaluation of debt to fair value.	
13

 
INDIAN RIVER POWER LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

(D)	 	Reflects management’s estimate, with the assistance of independent appraisers, of the fair value of SO2 emission credits.	
 	 	 	
(E)	 	Reflects the adjustment to deferred income tax assets and liabilities due to push down accounting.	
 	 	 	
(F)	 	The Asset Retirement Obligation (“ARO”) was revalued as part of push down accounting.	
 	 	 	
(G)	 	The change in member’s equity reflects the fair value adjustment resulting form NRG Energy’s Fresh Start accounting procedures.	

4.	Inventory	
      Inventory, which is valued at the lower of weighted average cost or market, consists of:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Fuel oil	 	$	378	 	 	$	415	 	 	$	307	 	
Spare parts	 	 	3,557	 	 	 	3,610	 	 	 	5,527	 	
Coal	 	 	9,767	 	 	 	7,375	 	 	 	14,640	 	

	 	 	 	

	 	 	 	

	 	
 	Total inventory	 	$	13,702	 	 	$	11,400	 	 	$	20,474	 	

	 	 	 	

	 	 	 	

	 	

5.	Property, Plant and Equipment	
      The major classes of property, plant and equipment were as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Predecessor	 	 	
 	 	Average	 	Reorganized Company	 	Company	 	 	
 	 	Remaining	 	

	 	

	 	 	
 	 	Useful	 	December 31,	 	December 6,	 	December 31,	 	Depreciable	
 	 	Life	 	2003	 	2003	 	2002	 	Lives	

	 	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Facilities and equipment	 	 	23 years	 	 	$	380,127	 	 	$	380,127	 	 	$	690,891	 	 	 	5-27 years	 	
Land and improvements	 	 	 	 	 	 	5,696	 	 	 	5,696	 	 	 	4,474	 	 	 	 	 	
Office furnishings and equipment	 	 	4 years	 	 	 	203	 	 	 	203	 	 	 	647	 	 	 	4-5 years	 	
Construction in progress	 	 	 	 	 	 	10,075	 	 	 	8,974	 	 	 	1,714	 	 	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	 	 	
 	Total property, plant and equipment	 	 	 	 	 	 	396,101	 	 	 	395,000	 	 	 	697,726	 	 	 	 	 	
Accumulated depreciation	 	 	 	 	 	 	(1,080	)	 	 	—	 	 	 	(34,445	)	 	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	 	 	
Property, plant and equipment, net	 	 	 	 	 	$	395,021	 	 	$	395,000	 	 	$	663,281	 	 	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	 	 	

6.	Asset Retirement Obligation	
      Effective January 1, 2003, the Company adopted SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires an entity to recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred. Upon initial recognition of a liability for an asset retirement obligation, an entity shall capitalize an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a

14

 
INDIAN RIVER POWER LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

legal obligation exists under enacted laws, statutes and written or oral contracts, including obligations arising under the doctrine of promissory estoppel.

      The Company identified an asset retirement obligation for future environmental obligations related to ash disposal site closure. The adoption of SFAS No. 143 resulted in recording a $1.4 million increase to property, plant and equipment and a $1.7 million increase to other long-term obligations. The cumulative effect of adopting SFAS No. 143 was recorded as a $0.2 million increase to depreciation expense and a $0.3 million increase to operating costs in the period from January 1, 2003 to December 5, 2003, as the Company considered the cumulative effect to be immaterial.

      The following represents the balances of the asset retirement obligation at January 1, 2003, and the additions and accretion of the asset retirement obligation for the period from January 1, 2003 to December 5, 2003 and the period from December 6, 2003 to December 31, 2003. As a result of applying push down accounting, the Company revalued its asset retirement obligations on December 6, 2003. The Company recorded an additional asset retirement obligation of $2.2 million in connection with push down accounting. This amount results from a change in the discount rate used between the date of adoption and December 5, 2003, equal to 500 to 600 basis points.

 	 	Predecessor Company	

	
 	 	 	 	Accretion	 	 	
 	 	Beginning	 	for Period	 	Adjustment	 	Ending	
 	 	Balance	 	Ended	 	for Fresh	 	Balance	
 	 	January 1,	 	December 5,	 	Start	 	December 5,	
 	 	2003	 	2003	 	Reporting	 	2003	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Landfill closure obligation	 	$	1,732	 	 	$	233	 	 	$	2,233	 	 	$	4,198	 	

 	 	Reorganized Company	

	
 	 	 	 	Accretion for	 	 	
 	 	Beginning	 	Period	 	Ending	
 	 	Balance	 	December 6 to	 	Balance	
 	 	December 6,	 	December 31,	 	December 31,	
 	 	2003	 	2003	 	2003	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Landfill closure obligation	 	$	4,198	 	 	$	24	 	 	$	4,222	 	
      The following represents the pro forma effect on the Company’s net income for the period from January 1, 2003 to December 5, 2003, and for the years ended December 31, 2002 and 2001, as if the Company had adopted SFAS No. 143 as of January 1, 2001:

 	 	Predecessor Company	

	
 	 	For the	 	 	
 	 	Period from	 	 	
 	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	December 31,	
 	 	December 5,	 	

	
 	 	2003	 	2002	 	2001	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Net income as reported	 	$	3,928	 	 	$	52,900	 	 	$	31,657	 	
Pro forma adjustment to reflect retroactive adoption of SFAS No. 143	 	 	101	 	 	 	(196	)	 	 	(93	)	

	 	 	 	

	 	 	 	

	 	
Pro forma net income	 	$	4,029	 	 	$	52,704	 	 	$	31,564	 	

	 	 	 	

	 	 	 	

	 	
      On a pro forma basis, an asset retirement obligation of $1.5 million and $1.7 million would have been recorded as other noncurrent liabilities as of January 1, 2002 and December 31, 2002, respectively, based on

15

 
INDIAN RIVER POWER LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

similar assumptions used to determine the amounts on the balance sheets at December 6, 2003 and December 31, 2003.

7.	Intangible Assets	
      The Company had intangible assets with a net carrying value of $57.5 million at December 6, 2003 and December 31, 2003, respectively. No intangible assets were recorded as of December 31, 2002. The intangible assets consisting of emission allowances will be amortized as additional fuel expense based upon the actual usage of the credits during any reporting period from the plant facilities through 2023. The annual amortization expense for each of the five succeeding years is expected to approximate $3.4 million each year. Intangible assets consisted of the following:

 	 	Reorganized Company	

	
 	 	 	 	 	
 	 	December 31, 2003	 	December 6, 2003	

	 	

	
 	 	Gross	 	 	 	Gross	 	 	
 	 	Carrying	 	Accumulated	 	Carrying	 	Accumulated	
 	 	Amount	 	Amortization	 	Amount	 	Amortization	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Intangible assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Emission allowances	 	$	57,531	 	 	$	—	 	 	$	57,531	 	 	$	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Total intangible assets	 	$	57,531	 	 	$	—	 	 	$	57,531	 	 	$	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
      No amortization was recorded during the period from December 6, 2003 to December 31, 2003, as this balance includes only emission allowances for 2004 and beyond. All emission allowances for 2003 were used prior to December 5, 2003.

8.	Long-Term Debt	
      On June 22, 2001, Mid Atlantic Gen borrowed approximately $420.9 million under a five-year term loan agreement (the “Agreement”) to finance, in part, the acquisition of certain generating facilities from Conectiv. Mid Atlantic Gen loaned the proceeds from the debt to its subsidiaries. The amount loaned by Mid Atlantic Gen to the Company was $317.3 million. As a result of cross-default provisions of the NRG Energy debt, the whole amount was classified as current at December 6, 2003 and December 31, 2002. On December 23, 2003, NRG Energy issued $1.25 billion in Second Priority Notes, due and payable on December 15, 2013. On the same date, NRG Energy also entered into a new credit facility for up to $1.45 billion. Proceeds of the December 23, 2003, Second Priority Note issuance and the new credit facility were used among other things, for repayment of secured debt held by the Company. The Company used proceeds of $254.7 million from a capital contribution from NRG Energy and payables to affiliates to pay the outstanding principal of $311 million and accrued interest of $2.5 million.

      The Agreement provided for a variable interest rate at either the higher of the Prime rate or the Federal Funds rate plus 0.5%, or the London Interbank Offered Rate (“LIBOR”) of interest. During the period from December 6, 2003 to December 31, 2003 and the period from January 1, 2003 to December 5, 2003, the weighted average interest rate for amounts outstanding under the Agreement was 4.375% and 4.506%, respectively. For the years ended December 31, 2002 and 2001, the weighted average interest rate was 3.30% and 4.56%, respectively. The Company was obligated to pay a commitment fee of 0.375% of the unused portion of the credit facility.

9.	Long-Term Contract	
      On June 22, 2001, Mid Atlantic Gen purchased 1,081 megawatts (“MW”) of interests in power generation plants from a subsidiary of Conectiv. Other liabilities, in the purchase price allocation, included

16

 
INDIAN RIVER POWER LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

$144.4 million associated with out-of-market contracts. The $144.4 million of out-of-market contracts included $72.4 million of current liabilities and $72.0 million of noncurrent liabilities as of the date of acquisition. The $144.4 million was comprised of three out-of-market contracts, two of which were less than one year in duration from the acquisition date and the third contract was in effect through 2005. Upon the acquisition, the Company assumed the remaining obligations under these short-term and long-term power purchase agreements. The short-term agreements required the Company to provide 895 MW of electrical energy around the clock at specified prices through August 2001 and 130 MW through September 2001. The long-term agreement required the Company to deliver 500 MW of electrical energy around the clock at a specified price through 2005. The sales price of the contracted electricity was substantially lower than the fair value of that electricity on the merchant market at the date of the acquisition. The out of market contract liability was amortized into revenue based on the terms of the power purchase agreements and the related estimates for the respective monthly electricity selling prices as of the date of acquisition. Accordingly, the Company recognized $89.3 million and $55.0 million in revenues associated with the amortization of the long-term and short-term power purchase agreements, respectively, during the years ended December 31, 2002 and 2001.

      On November 8, 2002, Conectiv provided NRG Energy with a Notice of Termination of Transaction under the Master Power Purchase and Sale Agreement (“Master PPA”) dated June 21, 2001, to terminate the long-term power purchase agreement. As a result of the cancellation, the Company lost approximately $383 million in future contracted revenues that would have been provided under the terms of the contract. In conjunction with the terms of the Master PPA, the Company received from Conectiv a termination payment in the amount of $955,000 which was recorded as revenue in 2002. As a result of the contract termination in 2002, the remaining unamortized balance of $44.3 million was brought into income as revenue.

10.	Sales to Significant Customers	
      During the period from December 6, 2003 to December 31, 2003, Atlantic City Electric, dba Conectiv, PJM Interconnections and Rockland Electric accounted for 45%, 39% and 16% of total revenues, respectively. During the period from January 1, 2003 to December 5, 2003, two customers accounted for 78% (Atlantic City Electric, dba Conectiv) and 13% (PJM Interconnnections) of total revenues. During 2002, one customer accounted for 95% (Atlantic City Electric, dba Conectiv) of total revenues. During 2001, one customer accounted for 45% (Conectiv) of total revenues. Such amounts include revenues from customers under contract with NRG Power Marketing, Inc.

11.	Related Party Transactions	
      On June 22, 2001, the Company entered into power sales and agency agreements with NRG Power Marketing Inc. (“NRG Power Marketing”), a wholly owned subsidiary of NRG Energy. The agreement is effective until December 31, 2030. Under the agreement, NRG Power Marketing will (i) have the exclusive right to manage, market and sell all power not otherwise sold or committed to by the Company, (ii) procure and provide to the Company all fuel required to operate its facilities and (iii) market, sell and purchase all emission credits owned, earned or acquired by the Company. In addition, NRG Power Marketing will have the exclusive right and obligation to effect the direction of the power output from the facilities.

      Under the agreement, NRG Power Marketing pays to the Company gross receipts generated through sales, less costs incurred by NRG Power Marketing relative to its providing services (e.g. transmission and delivery costs, fuel cost, taxes, employee labor, contract services, etc.). The Company incurred no fees related to these power sales and agency agreements with NRG Power Marketing.

      On June 22, 2001, the Company entered into an operation and maintenance agreement with a subsidiary of NRG Operating Services, Inc. (“NRG Operating Services”), a wholly owned subsidiary of NRG Energy. The agreement is effective for five years, with the option to extend beyond five years. Under the agreement,

17

 
INDIAN RIVER POWER LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

the NRG Operating Services company operator operates and maintains its respective facility, including (i) coordinating fuel delivery, unloading and inventory, (ii) managing facility spare parts, (iii) meeting external performance standards for transmission of electricity, (iv) providing operating and maintenance consulting and (v) cooperating with and assisting in performing the obligations under agreements related to facilities.

      Under the agreement, the operator will be reimbursed for usual and customary costs related to providing the services including plant labor and other operating costs. A demobilization payment will be made if the subsidiary elects not to renew the agreement. There are also incentive fees and penalties based on performance under the approved operating budget, the heat rate and safety.

      For the period from December 6, 2003 to December 31, 2003, the Company incurred operating costs billed from NRG Operating Services totaling $2.9 million. During the period from January 1, 2003 to December 5, 2003, the Company incurred operating costs billed from NRG Operating Services totaling $43.0 million. For the years ended December 31, 2002 and 2001, the Company incurred operating costs billed from NRG operating services totaling $43 million and $12 million, respectively.

      On June 22, 2001, the Company entered into an agreement with NRG Energy for corporate support and services. The agreement is perpetual in term, unless terminated in writing. Under the agreement, NRG Energy will provide services, as requested, in areas such as human resources, accounting, finance, treasury, tax, office administration, information technology, engineering, construction management, environmental, legal and safety. Under the agreement, NRG Energy is paid for personnel time as well as out-of-pocket costs. These costs are reflected in general and administrative expenses in the statements of operations. During the period from December 6, 2003 to December 31, 2003, the Company incurred expenses of $746,000 under this agreement. During the period from January 1, 2003 to December 5, 2003, the Company incurred expenses of $165,000 under this agreement. For the years ended December 31, 2002 and 2001, the Company incurred expenses of $134,000 and $85,000, respectively, under this agreement.

12.	Commitments and Contingencies	

 	Environmental Matters	
      The Company is responsible for the costs associated with closure, post-closure care and monitoring of the ash landfill owned and operated by the Company on the site of the Indian River Generating Station. No material liabilities outside such costs are expected. In accordance with certain regulations established by the Delaware Department of Natural Resources and Environmental Control, the Company has established a fully funded trust fund to provide for financial assurance for the closure and post-closure related costs in the amount of $6.6 million. The amounts contained in this fund will be dispensed as authorized by the Delaware Department of Natural Resources and Environmental Control. This amount is recorded in other noncurrent assets on the balance sheet.

      The Company estimates that it will incur capital expenditures of approximately $14.7 million during the years 2004 through 2008 related to resolving environmental concerns at the Indian River Generating Station. These concerns include the expected closure of the existing ash landfill, the construction of a new ash landfill nearby, the addition of controls to reduce NOx emissions, fuel yard modifications and electrostatic precipitator refurbishments to reduce opacity.

 	Guarantees	
      In November 2002, the FASB issued FIN 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others . The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor’s fiscal year end. The disclosure requirements

18

 
INDIAN RIVER POWER LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

are effective for financial statements of interim or annual periods ending after December 15, 2002. The interpretation addresses the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees. The interpretation also clarifies the requirements related to the recognition of a liability by a guarantor at the inception of the guarantee for the obligations the guarantor has undertaken in issuing the guarantee.

      In connection with push down accounting, all outstanding guarantees were considered new; accordingly, the Company applied the provisions of FIN 45 to all of those guarantees. Each guarantee was reviewed for the requirement to recognize a liability at inception.

      On December 23, 2003, the Company’s ultimate parent, NRG Energy, issued $1.25 billion of 8% Second Priority Notes, due and payable on December 15, 2013. On January 28, 2004, NRG Energy also issued $475.0 million of Second Priority Notes, under the same terms and indenture as its December 23, 2003 offering.

      NRG Energy’s payment obligations under the notes and all related Parity Lien Obligations are guaranteed on an unconditional basis by each of NRG Energy’s current and future restricted subsidiaries, of which the Company is one. The notes are jointly and severally guaranteed by each of the guarantors. The subsidiary guarantees of the notes are secured, on a second priority basis, equally and ratably with any future parity lien debt, by security interests in all of the assets of the guarantors, except certain excluded assets, subject to liens securing parity lien debt and other permitted prior liens.

      The Company’s obligations pursuant to its guarantees of the performance, equity and indebtedness obligations were as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantee/	 	 	 	 	 	 	
 	 	Maximum	 	 	 	Expiration	 	 	
 	 	Exposure	 	Nature of Guarantee	 	Date	 	Triggering Event	

	 	

	 	

	 	

	
 	 	(In thousands	 	 	 	 	 	 	
 	 	of dollars)	 	 	 	 	 	 	
Project/Subsidiary	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
NRG Energy Second Priority Notes due 2013	 	$	1,753,000	 	 	Obligations under credit agreement	 	 	2013	 	 	 	Nonperformance	 	

13.	Regulatory Issues	
      On April 2, 2003, Reliant Resources, Inc. (“Reliant”) filed a compliant against the Pennsylvania, Jersey, Maryland Interconnector area (“PJM”) with Federal Energy Regulatory Commission (“FERC”) and suggested specific modifications to PJM’s price mitigation rules. On June 9, 2003, FERC rejected the Reliant modifications but required PJM to file a report to address the concerns of Reliant by September 30, 2003. The PJM market monitoring unit filed its compliance filing with FERC as required, but opted to continue its present mitigation practices. The present mitigation plan permits PJM to “cost-cap” the energy bids of certain generating facilities that were constructed prior to 1996. The cost capping method is based on a facility’s variable costs plus 10%. In addition, the PJM market monitoring unit filed to eliminate the exemption that units built after 1996 had from PJM’s mitigation measures. On May 6, 2004, FERC rejected the proposed extension of the cost capping mechanism to generating facilities built after 1996. In the order, the FERC approved the application of the cost-capping mitigation method for facilities built prior to 1996 and were cost capped less than 80% of the time the facilities operated. The FERC required that for facilities that are cost capped 80% or more of their operating hours, are needed for reliability, and are not recovering sufficient revenue to cover their costs, that PJM must provide alternative methods of compensation. The FERC noted that such alternative compensation could consist of market design changes such as a higher bid cap or reliability must run agreements. FERC required that PJM file such a proposal by November 6, 2004. At this

19

 
INDIAN RIVER POWER LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

time it is unclear how this ruling will impact the Company. The Company continues to monitor these activities for any potential adverse impact to the Company’s financial position or results of operations.

      On June 30, 2004, the PJM Interconnection made a proposal to the PJM membership to replace the existing capacity market with a new resource adequacy product. The new resource adequacy product would have three components: (1) the addition of a demand curve with the installed capacity (“ICAP”) obligation; (2) a location ICAP obligation, if necessary; and (3) additional compensation for fast start and flexible units, if necessary. This proposal would not be effective until at least June 2006.

14.	Income Taxes	
      The Company is included in the consolidated tax return filings as a wholly owned indirect subsidiary of NRG Energy. Reflected in the financial statements and notes below are separate company federal and state tax provisions as if the Company had prepared separate filings. An income tax provision has been established on the accompanying financial statements as of the earliest period presented in order to reflect income taxes as if the Company filed its own tax return. The Company’s ultimate parent, NRG Energy, does not have a tax allocation agreement with its subsidiaries nor has it historically pushed down or allocated income taxes to non tax paying entities or entities such as the Company which are treated as disregarded entities for tax purposes. Because the Company is not a party to a tax sharing agreement, current tax expense (benefit) is recorded as a capital contribution from (distribution to) the Company’s parent. The cumulative effect of recording an income tax provision (benefit) and deferred taxes resulted in recording as of December 31, 2000, a net deferred tax liability of $46.0 million and a reduction to member’s equity of $46.0 million.

      The provision (benefit) for income taxes consists of the following:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Current	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Federal	 	$	—	 	 	$	—	 	 	$	—	 	 	$	3,024	 	
 	State	 	 	—	 	 	 	—	 	 	 	—	 	 	 	854	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	3,878	 	
Deferred	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Federal	 	 	(841	)	 	 	2,115	 	 	 	27,231	 	 	 	14,023	 	
 	State	 	 	(237	)	 	 	597	 	 	 	7,695	 	 	 	3,962	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	(1,078	)	 	 	2,712	 	 	 	34,926	 	 	 	17,985	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Total income tax expense (benefit)	 	$	(1,078	)	 	$	2,712	 	 	$	34,926	 	 	$	21,863	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Effective tax rate	 	 	40.8	%	 	 	40.8	%	 	 	39.8	%	 	 	40.9	%	
20

 
INDIAN RIVER POWER LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

      The pre-tax net (loss) income was as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
U.S. 	 	$	(2,640	)	 	$	6,640	 	 	$	87,826	 	 	$	53,520	 	
      The components of the net deferred income tax liability were:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Deferred tax liabilities	 	 	 	 	 	 	 	 	 	 	 	 	
 	Property	 	$	—	 	 	$	—	 	 	$	104,333	 	
 	Emissions credits	 	 	23,501	 	 	 	23,501	 	 	 	—	 	
 	Other	 	 	562	 	 	 	540	 	 	 	281	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total deferred tax liabilities	 	 	24,063	 	 	 	24,041	 	 	 	104,614	 	
Deferred tax assets	 	 	 	 	 	 	 	 	 	 	 	 	
 	Deferred compensation, accrued vacation and other reserves	 	 	—	 	 	 	—	 	 	 	117	 	
 	Property	 	 	5,985	 	 	 	6,060	 	 	 	—	 	
 	Asset retirement obligation	 	 	1,725	 	 	 	1,715	 	 	 	—	 	
 	Domestic tax loss carryforwards	 	 	733	 	 	 	—	 	 	 	5,619	 	
 	Other	 	 	432	 	 	 	—	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total deferred tax assets (before valuation allowance)	 	 	8,875	 	 	 	7,775	 	 	 	5,736	 	
Valuation allowance	 	 	—	 	 	 	—	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
Net deferred tax assets	 	 	8,875	 	 	 	7,775	 	 	 	5,736	 	

	 	 	 	

	 	 	 	

	 	
Net deferred tax liability	 	$	15,188	 	 	$	16,266	 	 	$	98,878	 	

	 	 	 	

	 	 	 	

	 	
      The net deferred tax liability (asset) consists of:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Current deferred tax liability (asset)	 	$	44	 	 	$	44	 	 	$	(117	)	
Noncurrent deferred tax liability	 	 	15,144	 	 	 	16,222	 	 	 	98,995	 	

	 	 	 	

	 	 	 	

	 	
Net deferred tax liability	 	$	15,188	 	 	$	16,266	 	 	$	98,878	 	

	 	 	 	

	 	 	 	

	 	
21

 
INDIAN RIVER POWER LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

      The effective income tax rates of continuing operations differ from the statutory federal income tax rate of 35% as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	 	 	 	 	
 	 	Company	 	 	 	Predecessor Company	 	 	

	 	 	 	

	 	 	
 	 	For the	 	 	 	For the	 	 	 	 	
 	 	Period from	 	 	 	Period from	 	 	 	 	 	 	
 	 	December 6,	 	 	 	January 1,	 	 	 	For the Years Ended	 	 	
 	 	2003 to	 	 	 	2003 to	 	 	 	December 31,	 	 	
 	 	December 31,	 	 	 	December 5,	 	 	 	

	 	 	
 	 	2003	 	 	 	2003	 	 	 	2002	 	 	 	2001	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	
 	 	 	
 	 	(In thousands of dollars)	
(Loss) income before taxes	 	$	(2,640	)	 	 	 	 	 	$	6,640	 	 	 	 	 	 	$	87,826	 	 	 	 	 	 	$	53,520	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	
Tax at 35%	 	 	(924	)	 	 	35.0%	 	 	 	2,324	 	 	 	35.0%	 	 	 	30,739	 	 	 	35.0%	 	 	 	18,732	 	 	 	35.0%	 	
State taxes (net of federal benefit)	 	 	(155	)	 	 	5.8%	 	 	 	389	 	 	 	5.8%	 	 	 	5,002	 	 	 	5.7%	 	 	 	3,131	 	 	 	5.9%	 	
Other	 	 	1	 	 	 	0.0%	 	 	 	(1	)	 	 	0.0%	 	 	 	(815	)	 	 	(0.9)%	 	 	 	—	 	 	 	0.0%	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	
Income tax (benefit) expense	 	$	(1,078	)	 	 	40.8%	 	 	$	2,712	 	 	 	40.8%	 	 	$	34,926	 	 	 	39.8%	 	 	$	21,863	 	 	 	40.9%	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	
      Income tax expense for all periods reflect the federal and state tax and there are no special tax credits.

22

 

EXHIBIT 99.5

NRG MID ATLANTIC GENERATING LLC

CONSOLIDATED FINANCIAL STATEMENTS

At December 31, 2003, December 6, 2003 and
December 31, 2002, and for the Period from
December 6, 2003 to December 31, 2003, the Period
from January 1, 2003 to December 5, 2003 and for
the Years Ended December 31, 2002 and 2001

 

NRG MID ATLANTIC GENERATING LLC

INDEX
 	 	 	 	 	
 	 	Page(s)	

	
Reports of Independent Auditors	 	 	2-3	 	
Consolidated Financial Statements	 	 	 	 	
Consolidated Balance Sheets at December 31, 2003, December 6, 2003 and December 31, 2002	 	 	4	 	
Consolidated Statements of Operations for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001	 	 	5	 	
Consolidated Statements of Member’s Equity for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001	 	 	6	 	
Consolidated Statements of Cash Flows for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001	 	 	7-8	 	
Notes to Consolidated Financial Statements	 	 	9-27	 	
1

 

REPORT OF INDEPENDENT AUDITORS

To the Members of
NRG Mid Atlantic Generating LLC

      In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, of members’ equity, and of cash flows present fairly, in all material respects, the financial position of NRG Mid Atlantic Generating LLC and its subsidiaries (“Predecessor Company”) at December 31, 2002, and the results of their operations and their cash flows for the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      As discussed in Note 1 to the consolidated financial statements, the Company’s ultimate parent, NRG Energy, Inc., filed a petition on May 14, 2003, with the United States Bankruptcy Court for the Southern District of New York for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. NRG Energy, Inc.’s Plan of Reorganization was substantially consummated on December 5, 2003, and Reorganized NRG emerged from bankruptcy. The impact of NRG Energy, Inc.’s emergence from bankruptcy and fresh start accounting was applied to the Company on December 5, 2003 under push down accounting methodology.

      As discussed in Note 17 to the consolidated financial statements, the Company has restated its previously issued consolidated financial statements for the years ended December 31, 2002 and 2001 to reflect an income tax provision (benefit) and deferred taxes.
 	 	
 	/s/ PRICEWATERHOUSECOOPERS LLP	

	
 	PricewaterhouseCoopers LLP	
Minneapolis, Minnesota
March 10, 2004

2

 

REPORT OF INDEPENDENT AUDITORS

To the Members of
NRG Mid Atlantic Generating LLC

      In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of members’ equity, and of cash flows present fairly, in all material respects, the financial position of NRG Mid Atlantic Generating LLC and its subsidiaries (“Reorganized Company”) at December 31, 2003 and December 6, 2003, and the results of their operations and their cash flows for the period from December 6, 2003 to December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      As discussed in Note 1 to the consolidated financial statements, the United States Bankruptcy Court for the Southern District of New York confirmed the NRG Energy, Inc., the Company’s ultimate parent, Plan of Reorganization on November 24, 2003. The NRG Energy, Inc. Plan of Reorganization was substantially consummated on December 5, 2003, and NRG Energy, Inc. emerged from bankruptcy. The impact of NRG Energy, Inc.’s emergence from bankruptcy and fresh start accounting was applied to the Company on December 5, 2003 under push down accounting methodology.
 	 	
 	/s/ PRICEWATERHOUSECOOPERS LLP	

	
 	PricewaterhouseCoopers LLP	
Minneapolis, Minnesota
March 10, 2004

3

 

NRG MID ATLANTIC GENERATING LLC

CONSOLIDATED BALANCE SHEETS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	 	 	 	(As Restated)	
 	 	 	
 	 	(In thousands of dollars)	
ASSETS	
Current assets	 	 	 	 	 	 	 	 	 	 	 	 	
 	Cash and cash equivalents	 	$	77	 	 	$	—	 	 	$	—	 	
 	Restricted cash	 	 	—	 	 	 	80,306	 	 	 	37,926	 	
 	Accounts receivable	 	 	—	 	 	 	—	 	 	 	15,733	 	
 	Accounts receivable — affiliates	 	 	5,155	 	 	 	6,390	 	 	 	—	 	
 	Inventory	 	 	17,611	 	 	 	14,841	 	 	 	26,255	 	
 	Derivative instruments valuation	 	 	161	 	 	 	161	 	 	 	4,053	 	
 	Prepayments and other current assets	 	 	2,385	 	 	 	2,823	 	 	 	12,532	 	
 	Current deferred income tax	 	 	—	 	 	 	—	 	 	 	1,448	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total current assets	 	 	25,389	 	 	 	104,521	 	 	 	97,947	 	
Property, plant and equipment, net of accumulated depreciation of $1,693, $0 and $44,217, respectively	 	 	565,201	 	 	 	565,700	 	 	 	796,718	 	
Debt issuance costs, net of accumulated amortization of $0, $0 and $2,591, respectively	 	 	—	 	 	 	—	 	 	 	6,047	 	
Investment in projects	 	 	1,280	 	 	 	1,280	 	 	 	—	 	
Intangible assets	 	 	68,469	 	 	 	68,469	 	 	 	—	 	
Other assets	 	 	6,753	 	 	 	6,749	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total assets	 	$	667,092	 	 	$	746,719	 	 	$	900,712	 	

	 	 	 	

	 	 	 	

	 	
 	
LIABILITIES AND MEMBERS’ EQUITY	
Current liabilities	 	 	 	 	 	 	 	 	 	 	 	 	
 	Current portion of long-term debt	 	$	—	 	 	$	406,560	 	 	$	409,201	 	
 	Accounts payable — trade	 	 	38	 	 	 	58	 	 	 	466	 	
 	Accounts payable — affiliates	 	 	259	 	 	 	31	 	 	 	108,487	 	
 	Accrued interest	 	 	—	 	 	 	3,269	 	 	 	62	 	
 	Accrued expenses	 	 	142	 	 	 	136	 	 	 	1,725	 	
 	Derivative instruments valuation	 	 	163	 	 	 	—	 	 	 	—	 	
 	Current deferred income tax	 	 	56	 	 	 	56	 	 	 	—	 	
 	Other current liabilities	 	 	285	 	 	 	463	 	 	 	364	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total current liabilities	 	 	943	 	 	 	410,573	 	 	 	520,305	 	
Noncurrent deferred income tax	 	 	32,979	 	 	 	33,987	 	 	 	101,126	 	
Other long-term obligations	 	 	4,256	 	 	 	4,232	 	 	 	82	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total liabilities	 	 	38,178	 	 	 	448,792	 	 	 	621,513	 	

	 	 	 	

	 	 	 	

	 	
Commitments and contingencies	 	 	 	 	 	 	 	 	 	 	 	 	
Members’ equity	 	 	628,914	 	 	 	297,927	 	 	 	279,199	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total liabilities and members’ equity	 	$	667,092	 	 	$	746,719	 	 	$	900,712	 	

	 	 	 	

	 	 	 	

	 	
The accompanying notes are an integral part of these consolidated financial statements.

4

 

NRG MID ATLANTIC GENERATING LLC

CONSOLIDATED STATEMENTS OF OPERATIONS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	 	 	 	(As Restated)	 	(As Restated)	
 	 	 	
 	 	(In thousands of dollars)	
Revenues	 	$	7,580	 	 	$	175,933	 	 	$	242,015	 	 	$	130,307	 	
Operating costs	 	 	6,317	 	 	 	117,753	 	 	 	97,830	 	 	 	44,822	 	
Depreciation	 	 	1,693	 	 	 	29,145	 	 	 	29,530	 	 	 	15,008	 	
General and administrative expenses	 	 	1,225	 	 	 	3,518	 	 	 	5,856	 	 	 	2,115	 	
Restructuring charges	 	 	—	 	 	 	1,599	 	 	 	—	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	(Loss) income from operations	 	 	(1,655	)	 	 	23,918	 	 	 	108,799	 	 	 	68,362	 	
Interest expense	 	 	(873	)	 	 	(18,740	)	 	 	(16,022	)	 	 	(11,597	)	
Other income (expense), net	 	 	47	 	 	 	1,053	 	 	 	132	 	 	 	(67	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	(Loss) income before income taxes	 	 	(2,481	)	 	 	6,231	 	 	 	92,909	 	 	 	56,698	 	
Income tax (benefit) expense	 	 	(1,008	)	 	 	2,532	 	 	 	38,097	 	 	 	23,037	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	Net (loss) income	 	$	(1,473	)	 	$	3,699	 	 	$	54,812	 	 	$	33,661	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
The accompanying notes are an integral part of these consolidated financial statements.

5

 

NRG MID ATLANTIC GENERATING LLC

CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY

 	 	Members’	 	Members’	 	Accumulated	 	Total	

	 	Contributions/	 	Net Income	 	Members’	
 	 	Units	 	Amount	 	Distributions	 	(Loss)	 	Equity	

	 	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Balances at December 31, 2000
(Predecessor Company) (As Restated)	 	 	1,000	 	 	$	1	 	 	$	6,147	 	 	$	—	 	 	$	6,148	 	
Net income	 	 	—	 	 	 	—	 	 	 	—	 	 	 	33,661	 	 	 	33,661	 	
Contribution from members	 	 	—	 	 	 	—	 	 	 	184,578	 	 	 	—	 	 	 	184,578	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Balances at December 31, 2001
(Predecessor Company) (As Restated)	 	 	1,000	 	 	 	1	 	 	 	190,725	 	 	 	33,661	 	 	 	224,387	 	
Net income	 	 	—	 	 	 	—	 	 	 	—	 	 	 	54,812	 	 	 	54,812	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Balances at December 31, 2002
(Predecessor Company) (As Restated)	 	 	1,000	 	 	 	1	 	 	 	190,725	 	 	 	88,473	 	 	 	279,199	 	
Net income	 	 	—	 	 	 	—	 	 	 	—	 	 	 	3,699	 	 	 	3,699	 	
Contribution from members	 	 	—	 	 	 	—	 	 	 	104,943	 	 	 	—	 	 	 	104,943	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Balances at December 5, 2003
(Predecessor Company)	 	 	1,000	 	 	 	1	 	 	 	295,668	 	 	 	92,172	 	 	 	387,841	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Push down accounting adjustment	 	 	—	 	 	 	—	 	 	 	2,258	 	 	 	(92,172	)	 	 	(89,914	)	
Balances at December 6, 2003
(Reorganized Company)	 	 	1,000	 	 	 	1	 	 	 	297,926	 	 	 	—	 	 	 	297,927	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Contribution from members	 	 	—	 	 	 	—	 	 	 	332,460	 	 	 	—	 	 	 	332,460	 	
Net loss	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(1,473	)	 	 	(1,473	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Balances at December 31, 2003
(Reorganized Company)	 	 	1,000	 	 	$	1	 	 	$	630,386	 	 	$	(1,473	)	 	$	628,914	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
The accompanying notes are an integral part of these consolidated financial statements.

6

 

NRG MID ATLANTIC GENERATING LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	 	 	 	(As Restated)	 	(As Restated)	
 	 	 	
 	 	(In thousands of dollars)	
Cash flows from operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net (loss) income	 	$	(1,473	)	 	$	3,699	 	 	$	54,812	 	 	$	33,661	 	
Adjustments to reconcile net (loss) income to net cash (used in) provided by operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Depreciation	 	 	1,693	 	 	 	29,145	 	 	 	29,530	 	 	 	15,008	 	
 	Amortization of power contracts	 	 	—	 	 	 	—	 	 	 	(89,251	)	 	 	(54,963	)	
 	Unrealized loss (gain) on derivatives	 	 	163	 	 	 	3,892	 	 	 	(4,442	)	 	 	390	 	
 	Amortization of debt issuance costs	 	 	—	 	 	 	1,607	 	 	 	2,345	 	 	 	246	 	
 	Deferred income taxes	 	 	(1,008	)	 	 	2,532	 	 	 	38,097	 	 	 	15,590	 	
 	Current tax expense — noncash contribution from members	 	 	—	 	 	 	—	 	 	 	—	 	 	 	7,447	 	
 	Changes in assets and liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Accounts receivable	 	 	—	 	 	 	15,733	 	 	 	2,592	 	 	 	(18,324	)	
Accounts receivable — affiliates	 	 	1,235	 	 	 	(6,390	)	 	 	—	 	 	 	—	 	
Inventory	 	 	(2,770	)	 	 	9,060	 	 	 	4,569	 	 	 	(6,188	)	
Prepayments and other current assets	 	 	438	 	 	 	9,709	 	 	 	(10,220	)	 	 	(2,312	)	
Other assets	 	 	(4	)	 	 	(6,749	)	 	 	—	 	 	 	—	 	
Accounts payable — trade	 	 	(20	)	 	 	(408	)	 	 	(2,552	)	 	 	3,018	 	
Accounts payable — affiliates	 	 	228	 	 	 	(108,456	)	 	 	38,861	 	 	 	25,054	 	
Accrued interest	 	 	(3,269	)	 	 	3,207	 	 	 	(2,769	)	 	 	2,634	 	
Changes in other assets and liabilities	 	 	(148	)	 	 	(986	)	 	 	1,692	 	 	 	(7,993	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	Net cash (used in) provided by operating activities	 	 	(4,935	)	 	 	(44,405	)	 	 	63,264	 	 	 	13,268	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Cash flows from investing activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Decrease (increase) in restricted cash	 	 	80,306	 	 	 	(42,380	)	 	 	(37,926	)	 	 	—	 	
Investment in projects	 	 	—	 	 	 	(1,280	)	 	 	—	 	 	 	—	 	
Acquisition, net of liabilities assumed	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(605,440	)	
Capital expenditures	 	 	(1,194	)	 	 	(14,237	)	 	 	(13,546	)	 	 	(13,368	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	Net cash provided by (used in) investing activities	 	 	79,112	 	 	 	(57,897	)	 	 	(51,472	)	 	 	(618,808	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
7

 
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	 	 	 	(As Restated)	 	(As Restated)	
 	 	 	
 	 	(In thousands of dollars)	
Cash flows from financing activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Bank overdraft	 	 	—	 	 	 	—	 	 	 	(100	)	 	 	100	 	
Proceeds from long-term borrowings	 	 	—	 	 	 	—	 	 	 	—	 	 	 	420,893	 	
Payments on long-term borrowings	 	 	(406,560	)	 	 	(2,641	)	 	 	(11,692	)	 	 	—	 	
Debt issuance costs	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(31	)	
Contribution from members	 	 	332,460	 	 	 	104,943	 	 	 	—	 	 	 	184,578	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	Net cash (used in) provided by financing activities	 	 	(74,100	)	 	 	102,302	 	 	 	(11,792	)	 	 	605,540	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	Net change in cash and cash equivalents	 	 	77	 	 	 	—	 	 	 	—	 	 	 	—	 	
Cash and cash equivalents	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Beginning of period	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
End of period	 	$	77	 	 	$	—	 	 	$	—	 	 	$	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Supplemental disclosures of cash flow information	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash paid for interest	 	$	4,093	 	 	$	13,860	 	 	$	18,791	 	 	$	8,963	 	
Noncash contribution for current tax expense	 	 	—	 	 	 	—	 	 	 	—	 	 	 	7,447	 	
Detail of assets acquired	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current assets	 	$	—	 	 	$	—	 	 	$	—	 	 	$	24,637	 	
Fair value of noncurrent assets	 	 	—	 	 	 	—	 	 	 	—	 	 	 	816,800	 	
Liabilities assumed	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(235,997	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Cash paid	 	$	—	 	 	$	—	 	 	$	—	 	 	$	605,440	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
The accompanying notes are an integral part of these consolidated financial statements.

8

 

NRG MID ATLANTIC GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.     Organization

      NRG Mid Atlantic Generating LLC (the “Company”), a wholly owned indirect subsidiary of NRG Energy, Inc (“NRG Energy”), owns electric power generation plants in the mid-atlantic region of the United States. The Company’s members are Mid Atlantic Generation Holding LLC (“Mid Atlantic Generation”) and NRG Mid Atlantic LLC (“NRG Mid Atlantic”) each of which owns a 50% interest in the Company and are directly held wholly owned subsidiaries of NRG Energy.

      The Company was formed in May, 2000 for the purpose of financing, acquiring, owning, operating and maintaining, through its subsidiaries the power generation facilities owned by Indian River Power LLC (“Indian River”), Vienna Power LLC (“Vienna”), Keystone Power LLC (“Keystone”) and Conemaugh Power LLC (“Conemaugh”).

 	Recent Developments	
      On May 14, 2003, NRG Energy and 25 of its direct and indirect wholly owned subsidiaries commenced voluntary petitions under Chapter 11 of the bankruptcy code in the United States Bankruptcy Court for the Southern District of New York. During the bankruptcy proceedings, NRG Energy continued to conduct business and manage the companies as debtors in possession pursuant to sections 1107(a) and 1108 of the bankruptcy code. The Company was not part of these Chapter 11 cases or any of the subsequent bankruptcy filings. On November 24, 2003, the bankruptcy court entered an order confirming NRG Energy’s Plan of Reorganization and the plan became effective on December 5, 2003. In connection with NRG Energy’s emergence from bankruptcy, NRG Energy adopted fresh start reporting in accordance with AICPA Statement of Position 90-7,  Financial Reporting by Entities in Reorganization Under the Bankruptcy Code  (“SOP 90-7”) on December 5, 2003. NRG Energy’s fresh start reporting was applied to the Company on a push down accounting basis with the financial statement impact recorded as an adjustment to the December 6, 2003, members’ equity in the amount of $89.9 million.

 	NRG Energy’s Plan of Reorganization	
      NRG Energy’s Plan of Reorganization is the result of several months of intense negotiations among NRG Energy, Xcel Energy, Inc. (“Xcel Energy”) and the two principal committees representing NRG Energy creditor groups, referred to as the Global Steering Committee and the Noteholder Committee. A principal component of NRG Energy’s Plan of Reorganization is a settlement with Xcel Energy in which Xcel Energy agreed to make a contribution consisting of cash (and, under certain circumstances, its stock) in the aggregate amount of up to $640 million to be paid in three separate installments following the effective date of NRG Energy’s Plan of Reorganization. The Xcel Energy settlement agreement resolves any and all claims existing between Xcel Energy and NRG Energy and/or its creditors and, in exchange for the Xcel Energy contribution, Xcel Energy is receiving a complete release of claims from NRG Energy and its creditors, except for a limited number of creditors who have preserved their claims as set forth in the confirmation order entered on November 24, 2003.

2.	Summary of Significant Accounting Policies	

 	Principles of Consolidation	
      The consolidated financial statements include the accounts of the Company and its subsidiaries. All significant intercompany transactions and balances have been eliminated in consolidation. Accounting policies for all of the Company’s operations are in accordance with the accounting principles generally accepted in the United States of America.

9

 
NRG MID ATLANTIC GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 	NRG Energy Fresh Start Reporting/Push Down Accounting	
      In accordance with SOP 90-7, certain companies qualify for fresh start (“Fresh Start”) reporting in connection with their emergence from bankruptcy. Fresh Start reporting is appropriate on the emergence from Chapter 11 if the reorganization value of the assets of the emerging entity immediately before the date of confirmation is less than the total of all post-petition liabilities and allowed claims, and if the holders of existing voting shares immediately before confirmation receive less than 50% of the voting shares of the emerging entity. NRG Energy met these requirements and adopted Fresh Start reporting and applied push down accounting to its various subsidiary operations including the Company. Under push down accounting, the Company’s equity fair value was allocated to the Company’s assets and liabilities based on their estimated fair values as of December 5, 2003, as further described in Note 3.

      Under the requirements of Fresh Start, NRG Energy adjusted its assets and liabilities, other than deferred income taxes, to their estimated fair values as of December 5, 2003. As a result of marking the assets and liabilities to their estimated fair values, NRG Energy determined that there was a negative reorganization value that was reallocated back to the tangible and intangible assets. Deferred taxes were determined in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 109,  Accounting for Income Taxes . The net effect of all Fresh Start adjustments resulted in a gain of $3.9 billion, which is reflected in NRG Energy’s Predecessor Company results for the period from January 1, 2003 to December 5, 2003. The application of the Fresh Start provisions of SOP 90-7 created a new reporting entity having no retained earnings or accumulated deficit.

      As part of the bankruptcy process, NRG Energy engaged an independent financial advisor to assist in the determination of its reorganized enterprise value. The fair value calculation was based on management’s forecast of expected cash flows from its core assets. Management’s forecast incorporated forward commodity market prices obtained from a third party consulting firm. A discounted cash flow calculation was used to develop the enterprise value of Reorganized NRG, determined in part by calculating the weighted average cost of capital of the Reorganized NRG. The Discounted Cash Flow, (“DCF,”) valuation methodology equates the value of an asset or business to the present value of expected future economic benefits to be generated by that asset or business. The DCF methodology is a “forward looking” approach that discounts expected future economic benefits by a theoretical or observed discount rate. The independent financial advisor prepared a 30-year cash flow forecast using a discount rate of approximately 11%. The resulting reorganization enterprise value as included in the Disclosure Statement ranged from $5.5 billion to $5.7 billion. The independent financial advisor then subtracted NRG Energy’s project level debt and made several other adjustments to reflect the values of assets held for sale, excess cash and collateral requirements to estimate a range of Reorganized NRG equity value of between $2.2 billion and $2.6 billion.

      In constructing the Fresh Start balance sheet upon emergence from bankruptcy, NRG Energy used a reorganization equity value of approximately $2.4 billion, as NRG Energy believed this value to be the best indication of the value of the ownership distributed to the new equity owners. NRG Energy’s Plan of Reorganization provided for the issuance of 100,000,000 shares of NRG Energy common stock to the various creditors resulting in a calculated price per share of $24.04. The reorganization value of approximately $9.1 billion was determined by adding the reorganized equity value of $2.4 billion, $3.7 billion of interest bearing debt and other liabilities of $3.0 billion. The reorganization value represents the fair value of an entity before liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after restructuring. This value is consistent with the voting creditors and Court’s approval of NRG Energy’s Plan of Reorganization.

      The application of SOP 90-7 and push down accounting resulted in the creation of a new reporting entity for the Company. Consequently, the consolidated financial statements of the Reorganized Company and the Predecessor Company are separated by a black line to distinguish that the assets, liabilities and members’ equity as well as the results of operations are not comparable between periods. Under the requirements of push

10

 
NRG MID ATLANTIC GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

down accounting, the Company has adjusted its assets and liabilities to their estimated fair values as of December 5, 2003. The impact of push down accounting resulted in the reduction of members’ equity for the Company in the amount of $89.9 million.

      For financial reporting purposes, close of business on December 5, 2003, represents the date of NRG Energy’s emergence from bankruptcy. As used herein, the following terms refer to the Company and its operations:
 	 	 	
“Predecessor Company”	 	The Company, prior to push down accounting	
 	 	The Company’s operations, January 1, 2001 - December 31, 2001	
 	 	The Company’s operations, January 1, 2002 - December 31, 2002	
 	 	The Company’s operations, January 1, 2003 - December 5, 2003	
“Reorganized Company”	 	The Company, post push down accounting	
 	 	The Company’s operations, December 6, 2003 - December 31, 2003	
      The bankruptcy court in its confirmation order approved NRG Energy’s Plan of Reorganization on November 24, 2003. Under the requirements of SOP 90-7, the Fresh Start date is determined to be the confirmation date unless significant uncertainties exist regarding the effectiveness of the bankruptcy order. The Plan of Reorganization required completion of the Xcel Energy settlement agreement prior to emergence from bankruptcy. Management believes this settlement agreement was a significant contingency and thus delayed the Fresh Start date until the Xcel Energy settlement agreement was finalized on December 5, 2003.

 	Cash and Cash Equivalents	
      Cash and cash equivalents include highly liquid investments with an original maturity of three months or less at the time of purchase.

 	Restricted Cash	
      Restricted cash consists primarily of funds that are restricted in use due to debt covenant violations. These violations are a result of cross-defaults caused by the downgrade of NRG Energy’s credit ratings and their failure to make certain debt payments. The cash is restricted from transfer or dividend from the Company to NRG Energy until such time as the debt covenant violations are cured. The restrictions were eliminated when the debt was repaid in December 2003.

 	              Inventory	
      Inventory consists of fuel oil, spare parts and coal and is valued at the lower of weighted average cost or market.

 	Property, Plant and Equipment	
      The Company’s property, plant and equipment are stated at cost; however, impairment adjustments are recorded whenever events or changes in circumstances indicate carrying values may not be recoverable. At December 5, 2003, the Company recorded adjustments to the property, plant and equipment to reflect such items at fair value in accordance with push down accounting. A new cost basis was established with these adjustments. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance that do not improve or extend the life of the respective asset, are charged to expense as incurred. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets. The assets and related accumulated depreciation amounts are adjusted for asset retirements and disposals, with the resulting gain or loss included in operations.

11

 
NRG MID ATLANTIC GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 	Asset Impairment	
      Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate carrying values may not be recoverable. Such reviews are performed in accordance with SFAS No. 144,  Accounting for the Impairment or Disposal of Long-lived Assets . An impairment loss is recognized if the total future estimated undiscounted cash flows expected from an asset are less than its carrying value. An impairment charge is measured by the difference between an asset’s carrying amount and fair value. Fair values are determined by a variety of valuation methods, including appraisals, sales prices of similar assets and present value techniques.

 	Debt Issuance Costs	
      Debt issuance costs consist of legal and other costs incurred to obtain debt financing. These costs, which were written off as part of push down accounting (see Note 3), were being amortized as interest expense on a basis that approximates the effective interest method over the terms of the related debt.

 	Intangible Assets	
      Intangible assets represent contractual rights held by the Company. Intangible assets are amortized over their economic useful life and reviewed for impairment on a periodic basis. Nonamortized intangible assets, including goodwill, are tested for impairment annually and on an interim basis if an event or circumstance occurs between annual tests that might reduce the fair value of that asset.

      Intangible assets consist of the fair value of emission allowances. Emission allowance related amounts will be amortized as additional fuel expense based upon the actual level of emissions from the respective plants through 2023.

      Effective January 1, 2002, the Company implemented SFAS No. 142, Goodwill and Other Intangible Assets. Pursuant to SFAS No. 142, goodwill is not amortized but is subject to periodic testing. At December 31, 2003, December 6, 2003 and December 31, 2002, the Company had no goodwill recorded in the consolidated financial statements.

 	Fair Value of Financial Instruments	
      The carrying amount of accounts receivable, accounts payable and accrued liabilities approximate fair value because of the short maturity of these instruments. The carrying amount of long-term debt approximates fair value due to the variable rate of interest associated with the long-term debt.

 	Income Taxes	
      The Company has been organized as a limited liability company. Therefore, federal and state income taxes are assessed at the member level. However, a provision for separate company federal and state income taxes has been reflected in the accompanying financial statements (see Note 17 — Income Taxes). As a result of the Company being included in the NRG Energy consolidated tax return and tax payments, federal and state taxes payable amounts resulting from the tax provision are reflected as a contribution by members in the consolidated statement of members’ equity and consolidated balance sheet.

      Deferred income taxes are recognized for the tax consequences in future years of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts at each year end based on enacted tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. Income tax expense is the tax payable for the period and the change during the period in deferred tax assets and liabilities. A valuation allowance is recorded to reduce deferred tax assets to the amount more likely than not to be realized.

12

 
NRG MID ATLANTIC GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 	Comprehensive Income	
      For all periods, net income is equal to comprehensive income as there were no additional items impacting comprehensive income for each of the periods presented.

 	Revenue Recognition	
      Revenues are recorded based on capacity provided and electrical output delivered at the lesser of amounts billable under the power purchase agreements, or the average estimated contract rates over the initial term of the contracts.

      In certain markets which are operated/controlled by an independent system operator (“ISO”) and in which the Company has entered into a netting agreement with the ISO, which results in the Company receiving a netted invoice, the Company records purchased energy as an offset against revenues received upon the sale of such energy. Disputed revenues are not recorded in the consolidated financial statements until disputes are resolved and collection is assured.

 	Power Marketing Activities	
      The Company’s subsidiaries have entered into agency agreements with a marketing affiliate for the sale of energy, capacity and ancillary services produced and for the procurement and management of fuel and emission credit allowances, which enable the affiliate to engage in forward sales and economic hedges to manage the Company’s electricity price exposure. Net gains or losses on hedges by the affiliate, which are physically settled, are recognized in the same manner as the hedged item. The Company receives the net transaction price on all contracts that are physically settled by its marketing affiliate.

 	Concentrations of Credit Risk	
      Financial instruments, which potentially subject the Company to concentrations of credit risk, consist primarily of cash, accounts receivable and investments in debt securities. Cash accounts are generally held in federally insured banks. Accounts receivable and derivative instruments are concentrated within entities engaged in the energy industry. These industry concentrations may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. Receivables are generally not collateralized; however, the Company believes the credit risk posed by industry concentration is offset by the diversification and credit worthiness of its customer base.

 	Use of Estimates in Financial Statements	
      The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenue and expenses during the reporting period. Actual results may differ from those estimates.

      In recording transactions and balances resulting from business operations, the Company uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, uncollectible accounts and the valuation of long-term energy commodities contracts, among others. In addition, estimates are used to test long-lived assets for impairment and to determine fair value of impaired assets. As better information becomes available (or actual amounts are determinable), the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

13

 
NRG MID ATLANTIC GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

3.	Emergence from Bankruptcy and Fresh Start Reporting	
      In accordance with the requirements of push down accounting, the Company’s fair value of $297.9 million was allocated to the Company’s assets and liabilities based on their individual estimated fair values. A third party was used to complete an independent appraisal of the Company’s tangible assets, intangible assets and contracts.

      The determination of the fair value of the Company’s assets and liabilities was based on a number of estimates and assumptions, which are inherently subject to significant uncertainties and contingencies.

      Due to the adoption of push down accounting as of December 5, 2003, the Reorganized Company’s consolidated balance sheets, consolidated statements of operations and cash flows have not been prepared on a consistent basis with the Predecessor Company’s consolidated financial statements and are not comparable in certain respects to the consolidated financial statements prior to the application of push down accounting. A black line has been drawn on the accompanying consolidated financial statements to separate and distinguish

14

 
NRG MID ATLANTIC GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

between the Reorganized Company and the Predecessor Company. The effects of the push down accounting adjustments on the Company’s consolidated balance sheet as of December 5, 2003, were as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor	 	 	 	Reorganized	
 	 	Company	 	 	 	Company	
 	 	December 5,	 	Push Down	 	December 6,	
 	 	2003	 	Adjustments	 	2003	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
ASSETS	
Current assets	 	 	 	 	 	 	 	 	 	 	 	 	
 	Restricted cash	 	$	80,306	 	 	$	—	 	 	$	80,306	 	
 	Accounts receivable — affiliates	 	 	6,390	 	 	 	—	 	 	 	6,390	 	
 	Inventory	 	 	17,195	 	 	 	(2,354	)(A)	 	 	14,841	 	
 	Derivative instruments valuation	 	 	161	 	 	 	—	 	 	 	161	 	
 	Prepayments and other current assets	 	 	2,823	 	 	 	—	 	 	 	2,823	 	
 	Current deferred income tax	 	 	1,405	 	 	 	(1,405	)(B)	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total current assets	 	 	108,280	 	 	 	(3,759	)	 	 	104,521	 	
Property, plant and equipment, net	 	 	783,268	 	 	 	(217,568	)(C)	 	 	565,700	 	
Debt issuance costs, net	 	 	4,438	 	 	 	(4,438	)(D)	 	 	—	 	
Investment in projects	 	 	1,280	 	 	 	—	 	 	 	1,280	 	
Intangible assets	 	 	—	 	 	 	68,469	(E)	 	 	68,469	 	
Other assets	 	 	6,749	 	 	 	—	 	 	 	6,749	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total assets	 	$	904,015	 	 	$	(157,296	)	 	$	746,719	 	

	 	 	 	

	 	 	 	

	 	
LIABILITIES AND MEMBERS’ EQUITY	
Current liabilities	 	 	 	 	 	 	 	 	 	 	 	 	
 	Current portion of long-term debt	 	$	406,560	 	 	$	—	 	 	$	406,560	 	
 	Accounts payable — trade	 	 	58	 	 	 	—	 	 	 	58	 	
 	Accounts payable — affiliates	 	 	31	 	 	 	—	 	 	 	31	 	
 	Accrued interest	 	 	3,269	 	 	 	—	 	 	 	3,269	 	
 	Accrued expenses	 	 	463	 	 	 	—	 	 	 	463	 	
 	Current deferred income tax	 	 	—	 	 	 	56	(B)	 	 	56	 	
 	Other current liabilities	 	 	136	 	 	 	—	 	 	 	136	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total current liabilities	 	 	410,517	 	 	 	56	 	 	 	410,573	 	
Deferred income tax	 	 	103,658	 	 	 	(69,671	)(B)	 	 	33,987	 	
Other current liabilities	 	 	1,999	 	 	 	2,233	 (F)	 	 	4,232	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total liabilities	 	 	516,174	 	 	 	(67,382	)	 	 	448,792	 	

	 	 	 	

	 	 	 	

	 	
Members’ equity	 	 	 	 	 	 	 	 	 	 	—	 	
 	Members’ contributions	 	 	295,669	 	 	 	2,258	 	 	 	297,927	 	
 	Accumulated net income	 	 	92,172	 	 	 	(92,172	)	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total members’ equity	 	 	387,841	 	 	 	(89,914	)(G)	 	 	297,927	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total liabilities and members’ equity	 	$	904,015	 	 	$	(157,296	)	 	$	746,719	 	

	 	 	 	

	 	 	 	

	 	
15

 
NRG MID ATLANTIC GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
 	 	 	
(A)	 	Accounting policy change upon adoption of push down accounting. Consumables are no longer included as inventory and are expensed as incurred. Capital spare parts were reclassified from inventory to property, plant and equipment.	
 	 	 	
(B)	 	Reflects the adjustment to deferred income tax assets and liabilities due to push down accounting.	
 	 	 	
(C)	 	Result of allocating the equity value in conformity with the purchase method of accounting for business combinations. These allocations were based on valuations obtained from independent appraisers.	
 	 	 	
(D)	 	Revaluation of debt to fair value.	
 	 	 	
(E)	 	Reflects management’s estimate, with the assistance of independent appraisers, of the fair value of SO2 emission credits.	
 	 	 	
(F)	 	The Asset Retirement Obligation (“ARO”) was revaluated as part of push down accounting.	
 	 	 	
(G)	 	The change in members’ equity reflects the fair value adjustment resulting from NRG Energy’s Fresh Start accounting procedures.	

4.	Restructuring Charges	
      The Company incurred total restructuring charges of approximately $1.6 million for the period January 1, 2003 to December 5, 2003. These costs consisted primarily of advisor fees.

5.	Inventory	
      Inventory, which is valued at the lower of weighted average cost or market, consists of:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Fuel oil	 	$	2,601	 	 	$	2,163	 	 	$	2,486	 	
Spare parts	 	 	5,188	 	 	 	5,245	 	 	 	7,615	 	
Coal	 	 	9,822	 	 	 	7,433	 	 	 	16,154	 	

	 	 	 	

	 	 	 	

	 	
 	Total inventory	 	$	17,611	 	 	$	14,841	 	 	$	26,255	 	

	 	 	 	

	 	 	 	

	 	

6.	Property, Plant and Equipment	
      The major classes of property, plant and equipment were as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Predecessor	 	 	
 	 	 	 	Reorganized Company	 	Company	 	 	

	 	

	 	Average	
 	 	Depreciable	 	December 31,	 	December 6,	 	December 31,	 	Remaining	
 	 	Lives	 	2003	 	2003	 	2002	 	Useful Life	

	 	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Land	 	 	 	 	 	$	19,386	 	 	$	19,386	 	 	$	5,397	 	 	 	 	 	
Facilities and equipment	 	 	2-27 years	 	 	 	536,925	 	 	 	536,925	 	 	 	828,019	 	 	 	22 years	 	
Construction work in progress	 	 	 	 	 	 	10,583	 	 	 	9,389	 	 	 	7,519	 	 	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	 	 	
 	Total property, plant and equipment	 	 	 	 	 	 	566,894	 	 	 	565,700	 	 	 	840,935	 	 	 	 	 	
Accumulated depreciation	 	 	 	 	 	 	(1,693	)	 	 	—	 	 	 	(44,217	)	 	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	 	 	
Property, plant and equipment, net	 	 	 	 	 	$	565,201	 	 	$	565,700	 	 	$	796,718	 	 	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	 	 	
16

 
NRG MID ATLANTIC GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

7.	Asset Retirement Obligation	
      Effective January 1, 2003, the Company adopted SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires an entity to recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred. Upon initial recognition of a liability for an asset retirement obligation, an entity shall capitalize an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes and written or oral contracts, including obligations arising under the doctrine of promissory estoppel.

      The Company identified an asset retirement obligation related to environmental obligations related to ash disposal site closures. The Company also identified other asset retirement obligations including plant dismantlement that could not be calculated because the assets associated with the retirement obligations were determined to have an indeterminate life. The adoption of SFAS No. 143 resulted in recording a $1.4 million increase to property, plant and equipment and a $1.7 million increase to other long-term obligations. The cumulative effect of adopting SFAS No. 143 was recorded as a $0.2 million increase to depreciation expense and a $0.3 million increase to operating costs in the period from January 1, 2003 to December 5, 2003, as the Company considered the cumulative effect to be immaterial.

      The following represents the balances of the asset retirement obligation at January 1, 2003, and the additions and accretion of the asset retirement obligation for the period from January 1, 2003 to December 5, 2003 and the period from December 6, 2003 to December 31, 2003, which is included in other long-term obligations in the consolidated balance sheets. Prior to December 5, 2003, the Company completed its annual review of asset retirement obligations. No change to the previously recorded obligation was necessary as a result of this review. As a result of applying push down accounting, the Company revalued its asset retirement obligation on December 6, 2003. The Company recorded an additional asset retirement obligation of $2.2 million in connection with push down accounting reporting. This amount results from a change in the discount rate used between the date of adoption and December 5, 2003, equal to 500 to 600 basis points.

 	 	Predecessor Company	

	
 	 	 	 	Accretion	 	 	
 	 	Beginning	 	for Period	 	Adjustment	 	Ending	
 	 	Balance	 	Ended	 	for Fresh	 	Balance	
 	 	January 1,	 	December 5,	 	Start	 	December 5,	
 	 	2003	 	2003	 	Reporting	 	2003	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Indian River landfill closure obligation	 	$	1,732	 	 	$	233	 	 	$	2,233	 	 	$	4,198	 	

 	 	Reorganized Company	

	
 	 	 	 	Accretion	 	 	
 	 	Beginning	 	for Period	 	Ending	
 	 	Balance	 	December 6 to	 	Balance	
 	 	December 6,	 	December 31,	 	December 31,	
 	 	2003	 	2003	 	2003	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Indian River landfill closure obligation	 	$	4,198	 	 	$	24	 	 	$	4,222	 	
17

 
NRG MID ATLANTIC GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The following represents the pro forma effect on the Company’s net income for the period from January 1, 2003 to December 5, 2003, and for the years ended December 31, 2002 and 2001, as if the Company had adopted SFAS No. 143 as of January 1, 2001:

 	 	Predecessor Company	

	
 	 	For the	 	 	
 	 	Period from	 	 	
 	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	December 31,	
 	 	December 5,	 	

	
 	 	2003	 	2002	 	2001	

	 	

	 	

	
 	 	 	 	(As Restated)	 	(As Restated)	
 	 	 	
 	 	(In thousands of dollars)	
Net income as reported	 	$	3,699	 	 	$	54,812	 	 	$	33,661	 	
Pro forma adjustment to reflect retroactive adoption of SFAS No. 143	 	 	101	 	 	 	(196	)	 	 	(93	)	

	 	 	 	

	 	 	 	

	 	
Pro forma net income	 	$	3,800	 	 	$	54,616	 	 	$	33,568	 	

	 	 	 	

	 	 	 	

	 	
      On a pro forma basis, an asset retirement obligation of $1.5 million and $1.7 million would have been recorded as other noncurrent liabilities at January 1, 2002 and December 31, 2002, respectively, based on similar assumptions used to determine the amounts on the Company’s consolidated balance sheets at December 6, 2003 and December 31, 2003.

8.	Intangible Assets	
      The Company had intangible assets with a net carrying value of $68.5 million at December 31, 2003 and December 6, 2003, respectively. No intangible assets were recorded at December 31, 2002. The intangible assets consisting of emission allowances which will be amortized as additional fuel expense based upon the actual usage of credits during any reporting period from the respective plants through 2023. The annual aggregate amortization expense for each of the five succeeding years is expected to approximate $4.2 million each year. Intangible assets consisted of the following:

 	 	Reorganized Company	

	
 	 	 	 	 	
 	 	December 31, 2003	 	December 6, 2003	

	 	

	
 	 	Gross	 	 	 	Gross	 	 	
 	 	Carrying	 	Accumulated	 	Carrying	 	Accumulated	
 	 	Amount	 	Amortization	 	Amount	 	Amortization	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Intangible asset	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Emission allowances	 	$	68,469	 	 	$	—	 	 	$	68,469	 	 	$	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Total intangible assets	 	$	68,469	 	 	$	—	 	 	$	68,469	 	 	$	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
      No amortization was recorded during the period from December 6, 2003 to December 31, 2003, as this balance includes only emission allowances for 2004 and beyond. All emission allowances for 2003 were used prior to December 5, 2003.

9.	Investments Accounted for by the Cost Method	
      The Company had investments of $1.3 million in two joint venture projects, Keystone Fuels LLC (3.70%) and Conemaugh Fuels LLC (3.72%), that were formed for the purpose of buying coal and selling such coal to Keystone and Conemaugh, or to any entity that manufacturers or produces synthetic fuel from coal for resale to Keystone or Conemaugh. The cost method of accounting is applied to such investments because the ownership structure prevents the Company from exercising a controlling influence over operating and financial policies of the projects.

18

 
NRG MID ATLANTIC GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

10.     Long-Term Debt

      On June 22, 2001, the Company borrowed approximately $420.9 million under a five-year term loan agreement (the “Agreement”) to finance, in part, the acquisition of certain generating facilities from Conectiv. As a result of cross-default provisions of the NRG Energy debt, the whole amount was classified as current at December 6, 2003 and December 31, 2002. On December 23, 2003, NRG Energy issued $1.25 billion in Second Priority Notes, due and payable on December 15, 2013. On the same date, NRG Energy also entered into a new credit facility for up to $1.45 billion. Proceeds of the December 23, 2003, Second Priority Note issuance and the new credit facility were used, among other things, for repayment of secured debt held by the Company. The Company used proceeds of $332.5 million from a capital contribution from NRG Energy and cash on hand to pay the outstanding principal of $406.6 million and $4.1 million in accrued interest.

      The Agreement provided for a variable interest rate at either the higher of the Prime rate or the Federal Funds rate plus 0.50%, or the London Interbank Offered Rate (“LIBOR”) of interest. During the period from December 6, 2003 to December 31, 2003 and the period from January 1, 2003 to December 5, 2003, the weighted average interest rate for amounts outstanding under the Agreement was 4.375% and 4.506%, respectively. For the years ended December 31, 2002 and 2001, the weighted average interest rate was 3.30% and 4.56%, respectively. The Company was obligated to pay a commitment fee of 0.375% of the unused portion of the credit facility.

11.	Long-Term Contract	
      On June 22, 2001, the Company purchased 1,081 megawatts (“MW”) of interests in power generation plants from a subsidiary of Conectiv. Other liabilities in the purchase price allocation included $144.4 million associated with out-of-market contracts. The $144.4 million of out-of-market contracts included $72.4 million of current liabilities and $72.0 million of noncurrent liabilities as of the date of acquisition. The $144.4 million was comprised of three out-of-market contracts, two of which were less than one year in duration from the acquisition date and the third contract was originally in effect through 2005. Upon the acquisition, the Company assumed the remaining obligations under these short-term and long-term power purchase agreements. The short-term agreements required the Company to provide 895 MW of electrical energy around the clock at specified prices through August 2001 and 130 MW through September 2001. The long-term agreement required the Company to deliver 500 MW of electrical energy around the clock at a specified price through 2005. The sales price of the contracted electricity was substantially lower than the fair value of that electricity on the merchant market at the date of the acquisition. The out of market contract liability was amortized into revenue based on the terms of the power purchase agreements and the related estimates for the respective monthly electricity selling prices as of the date of acquisition. Accordingly, the Company recognized $89.3 million and $55.0 million of revenues associated with the amortization of the long-term and short-term power purchase agreements, respectively, during the years ended December 31, 2002 and 2001.

      On November 8, 2002, Conectiv provided NRG Energy with a Notice of Termination of Transaction under the Master Power Purchase and Sale Agreement (“Master PPA”) dated June 21, 2001, to terminate the long-term power purchase agreement. As a result of the cancellation, the Company lost approximately $383 million in future contracted revenues that would have been provided under the terms of the contract. In conjunction with the terms of the Master PPA, the Company received from Conectiv a termination payment in the amount of $955,000 which was recorded as revenue in 2002. As a result of the contract termination in 2002, the remaining unamortized balance of $44.3 million was brought into income as revenue.

12.	Sales to Significant Customers	
      During the period from December 6, 2003 to December 31, 2003, three customers accounted for 38% (Atlantic City Electric, dba Conectiv), 49% (PJM Interconnections) of total revenues and Rockland Electric

19

 
NRG MID ATLANTIC GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

accounted for 13%. During the period from January 1, 2003 to December 5, 2003, two customers accounted for 60% (Atlantic City Electric, dba Conectiv) and 27% (PJM Interconnections) of total revenues. During 2002, one customer accounted for 96% (Atlantic City Electric, dba Conectiv) of total revenues. During 2001, one customer accounted for 47% (Conectiv) of total revenues. Such amounts include revenue from customers under contract with NRG Power Marketing, Inc.

13.	Derivative Instruments and Hedging Activity	
      On January 1, 2001, the Company adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 137, SFAS No. 138 and SFAS No. 149. SFAS No. 133 requires the Company to record all derivatives on the consolidated balance sheet at fair value. Changes in the fair value of nonhedge derivatives will be immediately recognized in earnings. The criteria used to determine if hedge accounting treatment is appropriate are (a) the designation of the hedge to an underlying exposure, (b) whether or not the overall risk is being reduced and (c) if there is a high degree of correlation between the value of the derivative instrument and the underlying obligation. Formal documentation of the hedging relationship, the nature of the underlying risk, the risk management objective, and the means by which effectiveness will be assessed is created at the inception of the hedge. Changes in fair values of derivatives accounted for as hedges will either be recognized in earnings as offsets to the changes in fair value of related hedged assets, liabilities and firm commitments or, for forecasted transactions, deferred and recorded as a component of other accumulated comprehensive income, (“OCI,”) until the hedged transactions occur and are recognized in earnings. The ineffective portion of a hedging derivative instrument’s change in fair value will be immediately recognized in earnings. The Company also formally assesses both at inception and at least quarterly thereafter, whether the derivatives that are used in hedging transactions are highly effective in offsetting the changes in either the fair value or cash flows of the hedged item. This assessment includes all components of each derivative’s gain or loss unless otherwise noted. When it is determined that a derivative ceases to be a highly effective hedge, hedge accounting is discontinued.

      The adoption of SFAS No. 133 on January 1, 2001, resulted in no amounts being recorded on the consolidated balance sheet as the Company had no derivatives at January 1, 2001. The Company had no derivatives accounted for as hedges at December 31, 2003, December 6, 2003 and December 31, 2002, and for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003, and for the years ended December 31, 2002 and 2001.

      SFAS No. 133 applies to the Company’s power sales contracts, gas purchase contracts and other energy related commodities financial instruments used to mitigate variability in earnings due to fluctuations in spot market prices, hedge fuel requirements at generation facilities and protect investments in fuel inventories. At December 31, 2003, the Company had various commodity contracts extending through December 2004. Under the accounting requirements of SFAS No. 133, these contracts are not designated as hedge transactions. In addition, these contracts meet the definition of being derivative instruments and thus for financial reporting purposes are recorded at fair value on the consolidated balance sheet with the unrealized gain or loss recorded within net income for the respective period.

20

 
NRG MID ATLANTIC GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 	Statement of Operations	
      The following table summarizes the effects of SFAS No. 133 on the Company’s statement of operations for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003, and for the years ended December 31, 2002 and 2001:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Year Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Gains (Losses)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues	 	$	(163	)	 	$	(994	)	 	$	1,052	 	 	$	102	 	
Costs of operations	 	 	—	 	 	 	(2,898	)	 	 	3,390	 	 	 	(492	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	Total statement of operations impact before tax	 	$	(163	)	 	$	(3,892	)	 	$	4,442	 	 	$	(390	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	

 	Energy Related Commodities	
      The Company is exposed to commodity price variability in electricity, emission allowances and natural gas, oil and coal used to meet fuel requirements. In order to manage these commodity price risks, the Company enters into financial instruments, which may take the form of fixed price, floating price or indexed sales or purchases, and options, such as puts, calls, basis transactions and swaps. The Company has accounted for these derivatives by recording the derivative at market value with the offset being charged to earnings.

      The Company’s earnings for the period from December 6, 2003 to December 31, 2003, were decreased by an unrealized loss of $0.2 million associated with changes in the fair value of energy related derivative instruments not accounted for as hedges in accordance with SFAS No. 133.

      The Company’s earnings for the period from January 1, 2003 to December 5, 2003, were decreased by an unrealized loss of $3.9 million associated with changes in the fair value of energy related derivative instruments not accounted for as hedges in accordance with SFAS No. 133.

      The Company’s earnings for the year ended December 31, 2002, were increased by an unrealized gain of $4.4 million associated with changes in the fair value of energy related derivative instruments not accounted for as hedges in accordance with SFAS No. 133.

      The Company’s earnings for the year ended December 31, 2001, were decreased by an unrealized loss of $0.4 million associated with changes in the fair value of energy related derivative instruments not accounted for as hedges in accordance with SFAS No. 133.

14.	Related Party Transactions	
      On June 22, 2001, Indian River, Vienna, Keystone and Conemaugh entered into power sales and agency agreements with NRG Power Marketing Inc. (“NRG Power Marketing”), a wholly owned subsidiary of NRG Energy. The agreement is effective until December 31, 2030. Under the agreement, NRG Power Marketing will (i) have the exclusive right to manage, market and sell all power not otherwise sold or committed to by such subsidiaries, (ii) procure and provide to such subsidiaries all fuel required to operate their respective facilities and (iii) market, sell and purchase all emission credits owned, earned or acquired by such subsidiaries. In addition, NRG Power Marketing will have the exclusive right and obligation to effect the direction of the power output from the facilities.

21

 
NRG MID ATLANTIC GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      Under the agreement, NRG Power Marketing pays to the Company gross receipts generated through sales, less costs incurred by NRG Power Marketing relative to its providing services (e.g. transmission and delivery costs, fuel cost, taxes, employee labor, contract services, etc.). The Company incurred no fees related to these power sales and agency agreements with NRG Power Marketing.

      On June 22, 2001, Indian River and Vienna entered into operation and maintenance agreements with a subsidiary of NRG Operating Services, Inc. (“NRG Operating Services”), a wholly owned subsidiary of NRG Energy. The agreements are effective for five years, with options to extend beyond five years. Under the agreement, the NRG Operating Services company operator operates and maintains its respective facility, including (i) coordinating fuel delivery, unloading and inventory, (ii) managing facility spare parts, (iii) meeting external performance standards for transmission of electricity, (iv) providing operating and maintenance consulting and (v) cooperating with and assisting in performing the obligations under agreements related to facilities.

      Under the agreement, the operator will be reimbursed for usual and customary costs related to providing the services including plant labor and other operating costs. A demobilization payment will be made if the subsidiary elects not to renew the agreement. There are also incentive fees and penalties based on performance under the approved operating budget, the heat rate and safety.

      For the period from December 6, 2003 to December 31, 2003, Indian River and Vienna incurred operating and maintenance costs billed from NRG Operating Services totaling $2.9 million and $227,000, respectively. During the period from January 1, 2003 to December 5, 2003, Indian River and Vienna incurred operating and maintenance costs billed from NRG Operating Services totaling $43 million and $4.5 million, respectively. During 2002, Indian River and Vienna incurred operating and maintenance costs billed from NRG Operating Services totaling $43 million and $6.5 million, respectively and during 2001, Indian River and Vienna incurred operating and maintenance costs billed for NRG Operating Services totaling $12 million and $2.4 million, respectively.

      On June 22, 2001, Indian River and Vienna entered into agreements with NRG Energy for corporate support and services. The agreements are perpetual in term, unless terminated in writing. Under the agreements, NRG Energy will provide services, as requested, in areas such as human resources, accounting, finance, treasury, tax, office administration, information technology, engineering, construction management, environmental, legal and safety. Under the agreement, NRG Energy is paid for personnel time as well as out-of-pocket costs. These costs are reflected in general and administrative expenses in the consolidated statements of operations. During the period from December 6, 2003 to December 31, 2003, Indian River and Vienna incurred expenses of $746,000 and $186,000, respectively, under these agreements. During the period from January 1, 2003 to December 5, 2003, Indian River and Vienna incurred expenses of $165,000 and $43,000, respectively. During 2002 and 2001, Indian River incurred expenses of $134,000 and $85,000, respectively, and Vienna incurred expenses of $57,000 and $25,000, respectively, under these agreements.

15.	Commitments and Contingencies	

 	Environmental Matters	
      The Company’s subsidiary, Indian River, is responsible for the costs associated with closure, post-closure care and monitoring of the ash landfill owned and operated by the Company on the site of the Indian River Generating Station. No material liabilities outside such costs are expected. In accordance with certain regulations established by the Delaware Department of Natural Resources and Environmental Control, the Company has established a fully funded trust fund to provide for financial assurance for the closure and post-closure related costs in the amount of $6.6 million. The amounts contained in this fund will be dispersed as authorized by the Delaware Department of Natural Resources and Environmental Control. This amount is recorded in other noncurrent assets on the consolidated balance sheets.

22

 
NRG MID ATLANTIC GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The Company estimates that it will incur capital expenditures of approximately $14.7 million during the years 2004 through 2008 related to resolving environmental concerns at the Indian River Generating Station. These concerns include the expected closure of the existing ash landfill, the construction of a new ash landfill nearby, the addition of controls to reduce NOx emissions, fuel yard modifications and electrostatic precipitator refurbishments to reduce opacity.

 	Guarantees	
      In November 2002, the FASB issued FIN 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.  The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor’s fiscal year end. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002. The interpretation addresses the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees. The interpretation also clarifies the requirements related to the recognition of a liability by a guarantor at the inceptions of the guarantee for the obligations the guarantor has undertaken in issuing the guarantee.

      In connection with push down accounting, all outstanding guarantees were considered new; accordingly, the Company applied the provisions of FIN 45 to all of those guarantees. Each guarantee was reviewed for the requirement to recognize a liability at inception.

      On December 23, 2003, the Company’s ultimate parent, NRG Energy, issued $1.25 billion of 8% Second Priority Notes, due and payable on December 15, 2013. On January 28, 2004, NRG Energy also issued $475.0 million of Second Priority Notes, under the same terms and indenture as its December 23, 2003 offering.

      NRG Energy’s payment obligations under the notes and all related Parity Lien Obligations are guaranteed on an unconditional basis by each of NRG Energy’s current and future restricted subsidiaries, of which the Company is one. The notes are jointly and severally guaranteed by each of the guarantors. The subsidiary guarantees of the notes are secured, on a second priority basis, equally and ratably with any future parity lien debt, by security interest in all of the assets of the guarantors, except certain excluded assets, subject to liens securing parity lien debt and other permitted prior liens.

      The Company’s obligations pursuant to its guarantees of the performance, equity and indebtedness obligations were as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantee/	 	 	 	Expiration	 	 	
 	 	Maximum Exposure	 	Nature of Guarantee	 	Date	 	Triggering Event	

	 	

	 	

	 	

	
 	 	(In thousands	 	 	 	 	 	 	
 	 	of dollars)	 	 	 	 	 	 	
Project/Subsidiary	 	 	 	 	 	 	 	 	 	 	 	 	
NRG Energy Second Priority Notes due 2013	 	$	1,753,000	 	 	Obligations under credit agreement	 	 	2013	 	 	Nonperformance	

16.	Regulatory Issues	
      On April 2, 2003, Reliant Resources, Inc. (“Reliant”) filed a compliant against the Pennsylvania, Jersey, Maryland Interconnector area (“PJM”) with The Federal Energy Regulatory Commission (“FERC”) and suggested specific modifications to PJM’s price mitigation rules. On June 9, 2003, FERC rejected the Reliant modifications but required PJM to file a report to address the concerns of Reliant by September 30, 2003. The PJM market monitoring unit filed its compliance filing with FERC as required, but opted to continue its

23

 
NRG MID ATLANTIC GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

present mitigation practices. The present mitigation plan permits PJM to “cost-cap” the energy bids of certain generating facilities that were constructed prior to 1996. The cost capping method is based on a facility’s variable costs plus 10%. In addition, the PJM market monitoring unit filed to eliminate the exemption that units built after 1996 had from PJM’s mitigation measures. On May 6, 2004, FERC rejected the proposed extension of the cost capping mechanism to generating facilities built after 1996. In the order, the FERC approved the application of cost-capping mitigation methods for facilities built prior to 1996 and were cost capped less than 80% of the time the facilities operated. The FERC required that for facilities that are cost capped 80% or more of their operating hours, are needed for reliability, and are not recovering sufficient revenue to cover their costs, that PJM must provide alternative methods of compensation. The FERC noted that such alternative compensation could consist of market design changes such as a higher bid cap or reliability must run agreements. FERC required that PJM file such a proposal by November 6, 2004. At this time it is unclear how this ruling will impact the Company. The Company continues to monitor these activities for any potential adverse impact to the Company’s financial position or results of operations.

      On June 30, 2004, the PJM Interconnection made a proposal to the PJM membership to replace the existing capacity market with a new resource adequacy product. The new resource adequacy product would have three components: (1) the addition of a demand curve with the installed capacity (“ICAP”) obligation; (2) a location ICAP obligation, if necessary; and (3) additional compensation for fast start and flexible units, if necessary. This proposal would not be effective until at least June 2006.

17.	Income Taxes (Restatement)	
      The Company is included in the consolidated tax return filings as a wholly owned indirect subsidiary of NRG Energy. Reflected in the financial statements and notes below are separate company federal and state tax provisions as if the Company had prepared separate filings. An income tax provision has been established on the accompanying financial statements as of the earliest period presented in order to reflect income taxes as if the Company filed its own tax return. The Company’s ultimate parent, NRG Energy, does not have a tax allocation agreement with its subsidiaries and prior to January 1, 2003, income taxes were not recorded or allocated to non tax paying entities or entities such as the Company which are treated as disregarded entities for tax purposes. Accordingly, the previously issued consolidated financial statements for the years ended December 31, 2002 and 2001, have been restated to include the effects of recording an income tax provision. Because the Company is not a party to a tax sharing agreement, current tax expense (benefit) is recorded as a capital contribution from (distribution to) the Company’s parent. The cumulative effect of recording an income tax provision (benefit) and deferred taxes resulted in recording as of December 31, 2000, a net deferred tax liability of $45.9 million and a reduction to members’ equity of $45.9 million.

24

 
NRG MID ATLANTIC GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The provision (benefit) for income taxes consists of the following:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Current	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Federal	 	$	—	 	 	$	—	 	 	$	—	 	 	$	5,860	 	
 	State	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1,587	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	7,447	 	
Deferred	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Federal	 	 	(793	)	 	 	1,992	 	 	 	29,977	 	 	 	12,267	 	
 	State	 	 	(215	)	 	 	540	 	 	 	8,120	 	 	 	3,323	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	(1,008	)	 	 	2,532	 	 	 	38,097	 	 	 	15,590	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Total income tax (benefit) expense	 	$	(1,008	)	 	$	2,532	 	 	$	38,097	 	 	$	23,037	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Effective tax rate	 	 	40.6	%	 	 	40.6	%	 	 	41.0	%	 	 	40.6	%	
      The pre-tax income (loss) was as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
U.S. 	 	$	(2,481	)	 	$	6,231	 	 	$	92,909	 	 	$	56,698	 	
25

 
NRG MID ATLANTIC GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The components of the net deferred income tax liability were:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Deferred tax liabilities	 	 	 	 	 	 	 	 	 	 	 	 	
 	Property	 	$	10,258	 	 	$	9,773	 	 	$	104,180	 	
 	Emissions credits	 	 	27,818	 	 	 	27,818	 	 	 	—	 	
 	Other	 	 	732	 	 	 	786	 	 	 	3,560	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total deferred tax liabilities	 	 	38,808	 	 	 	38,377	 	 	 	107,740	 	
Deferred tax assets	 	 	 	 	 	 	 	 	 	 	 	 	
 	Deferred compensation, accrued vacation and other reserves	 	 	—	 	 	 	—	 	 	 	3,295	 	
 	Domestic tax loss carryforwards	 	 	3,085	 	 	 	2,074	 	 	 	4,193	 	
 	Asset retirement obligation	 	 	1,715	 	 	 	1,706	 	 	 	—	 	
 	Other	 	 	973	 	 	 	554	 	 	 	574	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total deferred tax assets (before valuation allowance)	 	 	5,773	 	 	 	4,334	 	 	 	8,062	 	
Valuation allowance	 	 	—	 	 	 	—	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
Net deferred tax assets	 	 	5,773	 	 	 	4,334	 	 	 	8,062	 	

	 	 	 	

	 	 	 	

	 	
Net deferred tax liability	 	$	33,035	 	 	$	34,043	 	 	$	99,678	 	

	 	 	 	

	 	 	 	

	 	
      The net deferred tax liability (asset) consists of:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Current deferred tax liability (asset)	 	$	56	 	 	$	56	 	 	$	(1,448	)	
Noncurrent deferred tax liability	 	 	32,979	 	 	 	33,987	 	 	 	101,126	 	

	 	 	 	

	 	 	 	

	 	
Net deferred tax liability	 	$	33,035	 	 	$	34,043	 	 	$	99,678	 	

	 	 	 	

	 	 	 	

	 	
26

 
NRG MID ATLANTIC GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The effective income tax rates of continuing operations differ from the statutory federal income tax rate of 35% as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	 	 	 	 	
 	 	Company	 	 	 	Predecessor Company	 	 	

	 	 	 	

	 	 	
 	 	For the	 	 	 	For the	 	 	 	 	
 	 	Period from	 	 	 	Period from	 	 	 	 	 	 	
 	 	December 6,	 	 	 	January 1,	 	 	 	For the Years Ended	 	 	
 	 	2003 to	 	 	 	2003 to	 	 	 	December 31,	 	 	
 	 	December 31,	 	 	 	December 5,	 	 	 	

	 	 	
 	 	2003	 	 	 	2003	 	 	 	2002	 	 	 	2001	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	
 	 	 	
 	 	(In thousands of dollars)	
(Loss) income before taxes	 	$	(2,481	)	 	 	 	 	 	$	6,231	 	 	 	 	 	 	$	92,909	 	 	 	 	 	 	$	56,698	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	
Tax at 35%	 	 	(868	)	 	 	35.0%	 	 	 	2,180	 	 	 	35.0%	 	 	 	32,518	 	 	 	35.0%	 	 	 	19,844	 	 	 	35.0%	 	
State taxes (net of federal benefit)	 	 	(140	)	 	 	5.6%	 	 	 	352	 	 	 	5.6%	 	 	 	5,278	 	 	 	5.7%	 	 	 	3,191	 	 	 	5.6%	 	
Other	 	 	—	 	 	 	0.0%	 	 	 	—	 	 	 	—%	 	 	 	301	 	 	 	0.3%	 	 	 	2	 	 	 	0.0%	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	
Income tax (benefit) expense	 	$	(1,008	)	 	 	40.6%	 	 	$	2,532	 	 	 	40.6%	 	 	$	38,097	 	 	 	41.0%	 	 	$	23,037	 	 	 	40.6%	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	
27

 

EXHIBIT 99.6

NRG SOUTH CENTRAL GENERATING LLC

CONSOLIDATED FINANCIAL STATEMENTS

At December 31, 2003, December 6, 2003 and
December 31, 2002, and for the Period from
December 6, 2003 to December 31, 2003, the Period
from January 1, 2003 to December 5, 2003 and for
the Years Ended December 31, 2002 and 2001

 

NRG SOUTH CENTRAL GENERATING LLC

INDEX
 	 	 	 	 	
 	 	Page(s)	

	
Reports of Independent Auditors	 	 	2-3	 	
Consolidated Financial Statements	 	 	 	 	
Consolidated Balance Sheets at December 31, 2003, December 6, 2003 and December 31, 2002	 	 	4	 	
Consolidated Statements of Operations for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001	 	 	5	 	
Consolidated Statements of Members’ Equity for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001	 	 	6	 	
Consolidated Statements of Cash Flows for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001	 	 	7-8	 	
Notes to Consolidated Financial Statements	 	 	9-40	 	
Report of Independent Auditors on Financial Statement Schedule	 	 	41-42	 	
Financial Statement Schedule	 	 	43	 	
1

 

REPORT OF INDEPENDENT AUDITORS

To the Members of
NRG South Central Generating LLC

      In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, of members’ equity and of cash flows present fairly, in all material respects, the financial position of NRG South Central Generating LLC and its subsidiaries (“Predecessor Company”) at December 31, 2002, and the results of their operations and their cash flows for the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      As discussed in Note 1 to the consolidated financial statements, on May 14, 2003, NRG Energy, Inc. and certain of its subsidiaries including the Company, filed a petition with the United States Bankruptcy Court for the Southern District of New York for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. NRG Energy, Inc.’s Plan of Reorganization was substantially consummated on December 5, 2003, and Reorganized NRG emerged from bankruptcy. The Company emerged from bankruptcy on December 23, 2003, pursuant to a separate plan of reorganization referred to as the Northeast/ South Central Plan of Reorganization. The impact of NRG Energy, Inc.’s emergence from bankruptcy and fresh start accounting was applied to the Company on December 5, 2003 under push down accounting methodology.

      As discussed in Note 21 to the consolidated financial statements, the Company has restated its previously issued consolidated financial statements for the years ended December 31, 2002 and 2001 to reflect an income tax provision (benefit) and deferred taxes.
 	 	
 	/s/ PRICEWATERHOUSECOOPERS LLP	

	
 	PricewaterhouseCoopers LLP	
Minneapolis, Minnesota
March 10, 2004

2

 

REPORT OF INDEPENDENT AUDITORS

To the Members of
NRG South Central Generating LLC

      In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of members’ equity and of cash flows present fairly, in all material respects, the financial position of NRG South Central Generating LLC and its subsidiaries (“Reorganized Company”) at December 31, 2003 and December 6, 2003, and the results of their operations and their cash flows for the period from December 6, 2003 to December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      As discussed in Note 1 to the consolidated financial statements, on May 14, 2003, NRG Energy, Inc. and certain of its subsidiaries including the Company, filed a petition with the United States Bankruptcy Court for the Southern District of New York for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. NRG Energy, Inc.’s Plan of Reorganization was substantially consummated on December 5, 2003, and Reorganized NRG emerged from bankruptcy. The Company emerged from bankruptcy on December 23, 2003, pursuant to a separate plan of reorganization referred to as the Northeast/ South Central Plan of Reorganization. The impact of NRG Energy, Inc.’s emergence from bankruptcy and fresh start accounting was applied to the Company on December 5, 2003 under push down accounting methodology.
 	 	
 	/s/ PRICEWATERHOUSECOOPERS LLP	

	
 	PricewaterhouseCoopers LLP	
Minneapolis, Minnesota
March 10, 2004

3

 

NRG SOUTH CENTRAL GENERATING LLC

CONSOLIDATED BALANCE SHEETS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	 	 	 	(As Restated)	
 	 	 	
 	 	(In thousands of dollars)	
ASSETS	
Current assets	 	 	 	 	 	 	 	 	 	 	 	 	
 	Cash and cash equivalents	 	$	4,612	 	 	$	11,398	 	 	$	310	 	
 	Restricted cash	 	 	99	 	 	 	133,793	 	 	 	109,336	 	
 	Accounts receivable	 	 	37,080	 	 	 	37,753	 	 	 	46,338	 	
 	Accounts receivable — affiliates	 	 	3,328	 	 	 	4,751	 	 	 	—	 	
 	Notes receivable	 	 	584	 	 	 	1,500	 	 	 	3,000	 	
 	Inventory	 	 	35,098	 	 	 	40,423	 	 	 	64,364	 	
 	Derivative instruments valuation	 	 	—	 	 	 	—	 	 	 	112	 	
 	Prepayments and other current assets	 	 	7,079	 	 	 	8,647	 	 	 	3,236	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total current assets	 	 	87,880	 	 	 	238,265	 	 	 	226,696	 	
Property, plant and equipment, net of accumulated depreciation of $2,561, $0 and $83,242, respectively	 	 	914,941	 	 	 	917,173	 	 	 	1,131,896	 	
Decommissioning fund investments	 	 	4,809	 	 	 	4,809	 	 	 	4,617	 	
Debt issuance costs, net of accumulated amortization of $0, $0 and $1,853, respectively	 	 	—	 	 	 	—	 	 	 	30,028	 	
Intangible assets, net of amortization of $787, $0 and $123, respectively	 	 	120,992	 	 	 	121,779	 	 	 	1,662	 	
Other assets	 	 	3,111	 	 	 	3,089	 	 	 	5,445	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total assets	 	$	1,131,733	 	 	$	1,285,115	 	 	$	1,400,344	 	

	 	 	 	

	 	 	 	

	 	
 	
LIABILITIES AND MEMBERS’ EQUITY	
Current liabilities	 	 	 	 	 	 	 	 	 	 	 	 	
 	Current portion of long-term debt	 	$	—	 	 	$	750,750	 	 	$	750,750	 	
 	Note payable — affiliate	 	 	81,673	 	 	 	81,491	 	 	 	105,491	 	
 	Accounts payable	 	 	10,476	 	 	 	15,279	 	 	 	9,814	 	
 	Accounts payable — affiliates	 	 	—	 	 	 	—	 	 	 	126,522	 	
 	Accrued interest	 	 	 —	 	 	 	15,296	 	 	 	55,413	 	
 	Accrued interest — affiliate	 	 	7,434	 	 	 	6,925	 	 	 	514	 	
 	Derivative instruments valuation	 	 	73	 	 	 	—	 	 	 	135	 	
 	Other current liabilities	 	 	18,452	 	 	 	32,764	 	 	 	21,817	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total current liabilities	 	 	118,108	 	 	 	902,505	 	 	 	1,070,456	 	
Burdensome contracts	 	 	341,004	 	 	 	342,210	 	 	 	—	 	
Other long-term obligations	 	 	9,789	 	 	 	10,191	 	 	 	6,238	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total liabilities	 	 	468,901	 	 	 	1,254,906	 	 	 	1,076,694	 	

	 	 	 	

	 	 	 	

	 	
Commitments and contingencies	 	 	 	 	 	 	 	 	 	 	 	 	
Members’ equity	 	 	662,832	 	 	 	30,209	 	 	 	323,650	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total liabilities and members’ equity	 	$	1,131,733	 	 	$	1,285,115	 	 	$	1,400,344	 	

	 	 	 	

	 	 	 	

	 	
The accompanying notes are an integral part of these consolidated financial statements.

4

 

NRG SOUTH CENTRAL GENERATING LLC

CONSOLIDATED STATEMENTS OF OPERATIONS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	 	 	 	(As Restated)	 	(As Restated)	
 	 	 	
 	 	(In thousands of dollars)	
Revenues	 	$	26,608	 	 	$	356,535	 	 	$	399,866	 	 	$	399,395	 	
Operating costs	 	 	17,514	 	 	 	236,216	 	 	 	262,361	 	 	 	276,554	 	
Depreciation and amortization	 	 	2,561	 	 	 	33,988	 	 	 	35,964	 	 	 	29,878	 	
General and administrative expenses	 	 	1,901	 	 	 	10,687	 	 	 	7,948	 	 	 	7,566	 	
Reorganization items	 	 	104	 	 	 	31,120	 	 	 	—	 	 	 	—	 	
Restructuring and impairment charges	 	 	—	 	 	 	—	 	 	 	139,929	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	Income (loss) from operations	 	 	4,528	 	 	 	44,524	 	 	 	(46,336	)	 	 	85,397	 	
Other income (expense), net	 	 	99	 	 	 	1,475	 	 	 	923	 	 	 	(189	)	
Losses of unconsolidated affiliates	 	 	—	 	 	 	—	 	 	 	(3,146	)	 	 	(2,435	)	
Write downs and losses on sale of equity	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
investments	 	 	—	 	 	 	—	 	 	 	(48,375	)	 	 	—	 	
Interest expense	 	 	(4,133	)	 	 	(73,968	)	 	 	(74,940	)	 	 	(72,665	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	Income (loss) before income taxes	 	 	494	 	 	 	(27,969	)	 	 	(171,874	)	 	 	10,108	 	
Income tax expense (benefit)	 	 	201	 	 	 	—	 	 	 	(39,789	)	 	 	4,093	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	Net income (loss)	 	$	293	 	 	$	(27,969	)	 	$	(132,085	)	 	$	6,015	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
The accompanying notes are an integral part of these consolidated financial statements.

5

 

NRG SOUTH CENTRAL GENERATING LLC

CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	Accumulated	 	 	
 	 	Members’	 	Members’	 	Accumulated	 	Other	 	Total	

	 	Contributions/	 	Net Income	 	Comprehensive	 	Members’	
 	 	Units	 	Amount	 	Distributions	 	(Loss)	 	Income	 	Equity	

	 	

	 	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Balances at December 31, 2000 (Predecessor Company) (As Restated)	 	 	1,000	 	 	$	1	 	 	$	275,507	 	 	$	15,558	 	 	$	—	 	 	$	291,066	 	
Cumulative effect upon adoption of SFAS No. 133	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	500	 	 	 	500	 	
Impact of SFAS No. 133 for the year ending December 31, 2001	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(500	)	 	 	(500	)	
Net income	 	 	—	 	 	 	—	 	 	 	—	 	 	 	6,015	 	 	 	—	 	 	 	6,015	 	

	 	
Comprehensive income	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	6,015	 	
Contribution from members	 	 	—	 	 	 	—	 	 	 	108,643	 	 	 	—	 	 	 	—	 	 	 	108,643	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Balances at December 31, 2001 (Predecessor Company) (As Restated)	 	 	1,000	 	 	 	1	 	 	 	384,150	 	 	 	21,573	 	 	 	—	 	 	 	405,724	 	
Net loss and comprehensive loss	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(132,085	)	 	 	—	 	 	 	(132,085	)	
Contribution from members	 	 	—	 	 	 	—	 	 	 	50,011	 	 	 	—	 	 	 	—	 	 	 	50,011	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Balances at December 31, 2002 (Predecessor Company) (As Restated)	 	 	1,000	 	 	 	1	 	 	 	434,161	 	 	 	(110,512	)	 	 	—	 	 	 	323,650	 	
Net loss and comprehensive loss	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(27,969	)	 	 	—	 	 	 	(27,969	)	
Contribution from members	 	 	—	 	 	 	—	 	 	 	150,878	 	 	 	—	 	 	 	—	 	 	 	150,878	 	
Balances at December 5, 2003 (Predecessor Company)	 	 	1,000	 	 	 	1	 	 	 	585,039	 	 	 	(138,481	)	 	 	—	 	 	 	446,559	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Push down accounting adjustment	 	 	—	 	 	 	—	 	 	 	(554,831	)	 	 	138,481	 	 	 	—	 	 	 	(416,350	)	
Balances at December 6, 2003 (Reorganized Company)	 	 	1,000	 	 	 	1	 	 	 	30,208	 	 	 	—	 	 	 	—	 	 	 	30,209	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Contribution from members	 	 	—	 	 	 	—	 	 	 	632,330	 	 	 	—	 	 	 	—	 	 	 	632,330	 	
Net income and comprehensive income	 	 	—	 	 	 	—	 	 	 	—	 	 	 	293	 	 	 	—	 	 	 	293	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Balances at December 31, 2003 (Reorganized Company)	 	 	1,000	 	 	$	1	 	 	$	662,538	 	 	$	293	 	 	$	—	 	 	$	662,832	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
      The accompanying notes are an integral part of these consolidated financial statements.

6

 

NRG SOUTH CENTRAL GENERATING LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	 	 	 	(As Restated)	 	(As Restated)	
 	 	 	 	 	
 	 	 	 	(In thousands of dollars)	
Cash flows from operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	$	293	 	 	$	(27,969	)	 	$	(132,085	)	 	$	6,015	 	
Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Equity in losses of unconsolidated affiliates in excess of distributions	 	 	—	 	 	 	—	 	 	 	3,146	 	 	 	2,435	 	
 	Depreciation and amortization	 	 	2,561	 	 	 	33,988	 	 	 	35,964	 	 	 	29,878	 	
 	Deferred income taxes	 	 	201	 	 	 	—	 	 	 	(39,789	)	 	 	4,093	 	
 	Loss on sale of equity method investments	 	 	—	 	 	 	—	 	 	 	48,375	 	 	 	—	 	
 	Reorganization items	 	 	—	 	 	 	9,141	 	 	 	—	 	 	 	—	 	
 	Special charges	 	 	—	 	 	 	4,367	 	 	 	138,578	 	 	 	—	 	
 	Amortization of debt issuance costs	 	 	—	 	 	 	1,557	 	 	 	1,103	 	 	 	427	 	
 	Amortization of debt discount	 	 	182	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	Amortization of out-of-market power contracts	 	 	(2,199	)	 	 	—	 	 	 	—	 	 	 	—	 	
 	Unrealized (gain) loss on derivatives	 	 	(994	)	 	 	—	 	 	 	5	 	 	 	18	 	
 	Changes in assets and liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Accounts receivable	 	 	673	 	 	 	8,585	 	 	 	(2,216	)	 	 	8,522	 	
 	 	Inventory	 	 	5,325	 	 	 	16,394	 	 	 	(11,448	)	 	 	(28,702	)	
 	 	Prepayments and other current assets	 	 	1,568	 	 	 	(5,411	)	 	 	(609	)	 	 	(792	)	
 	 	Accounts payable	 	 	(4,803	)	 	 	(4,838	)	 	 	(6,806	)	 	 	9,571	 	
 	 	Accounts receivable — affiliates	 	 	1,423	 	 	 	(131,787	)	 	 	58,220	 	 	 	(45,605	)	
 	 	Accrued interest	 	 	(14,787	)	 	 	(33,192	)	 	 	35,474	 	 	 	(857	)	
 	 	Other current assets and liabilities	 	 	(14,312	)	 	 	21,227	 	 	 	2,160	 	 	 	4,271	 	
 	 	Changes in other assets and liabilities	 	 	2,222	 	 	 	(285	)	 	 	559	 	 	 	184	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	Net cash (used in) provided by operating activities	 	 	(22,647	)	 	 	(108,223	)	 	 	130,631	 	 	 	(10,542	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Cash flows from investing activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Capital expenditures	 	 	(329	)	 	 	(8,610	)	 	 	(12,231	)	 	 	(8,866	)	
Increase (decrease) in notes receivable	 	 	916	 	 	 	1,500	 	 	 	(3,000	)	 	 	—	 	
Decrease (increase) in restricted cash	 	 	133,694	 	 	 	(24,457	)	 	 	(109,336	)	 	 	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	Net cash provided by (used in) investing activities	 	 	134,281	 	 	 	(31,567	)	 	 	(124,567	)	 	 	(8,866	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Cash flows from financing activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Contribution by members	 	 	632,330	 	 	 	150,878	 	 	 	48,000	 	 	 	5,051	 	
Net proceeds (payments) on revolving credit facility	 	 	—	 	 	 	—	 	 	 	(40,000	)	 	 	40,000	 	
Repayments of long-term borrowings	 	 	(750,750	)	 	 	—	 	 	 	(12,750	)	 	 	(25,250	)	
Repayment of note payable — affiliate	 	 	—	 	 	 	—	 	 	 	(1,862	)	 	 	—	 	
Checks in excess of cash	 	 	—	 	 	 	—	 	 	 	(2,350	)	 	 	(331	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	Net cash (used in) provided by financing activities	 	 	(118,420	)	 	 	150,878	 	 	 	(8,962	)	 	 	19,470	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	Net change in cash and cash equivalents	 	 	(6,786	)	 	 	11,088	 	 	 	(2,898	)	 	 	62	 	
7

 
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	 	 	 	(As Restated)	 	(As Restated)	
 	 	 	 	 	
 	 	 	 	(In thousands of dollars)	
Cash and cash equivalents	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Beginning of period	 	 	11,398	 	 	 	310	 	 	 	3,208	 	 	 	3,146	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
End of period	 	$	4,612	 	 	$	11,398	 	 	$	310	 	 	$	3,208	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Supplemental disclosures of cash flow information	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Interest paid	 	$	29,999	 	 	$	105,785	 	 	$	39,466	 	 	$	73,048	 	
Supplemental disclosures of noncash information	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Capital expenditures paid by affiliate	 	 	—	 	 	 	—	 	 	 	127,247	 	 	 	—	 	
Debt issuance costs funded through accounts payable — affiliate	 	 	—	 	 	 	—	 	 	 	21,162	 	 	 	—	 	
Noncash equity contributions	 	 	—	 	 	 	—	 	 	 	2,011	 	 	 	103,592	 	
The accompanying notes are an integral part of these consolidated financial statements.

8

 

NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.     Organization

      NRG South Central Generating LLC (“NRG South Central” or the “Company”) was formed in 2000 as an indirect wholly owned subsidiary of NRG Energy, Inc. (“NRG Energy”). NRG South Central owns 100% of Louisiana Generating LLC (“Louisiana Generating”), NRG New Roads Holding LLC (“New Roads”), NRG Sterlington Power LLC (“Sterlington”), Big Cajun I Peaking Power LLC (“Big Cajun Peaking”) and NRG Bayou Cove LLC (“Bayou Cove”). NRG South Central’s members are NRG Central U.S. LLC (“NRG Central”) and South Central Generation Holding LLC (“South Central Generation”). NRG Central and South Central Generation are directly held wholly owned subsidiaries of NRG Energy, each of which owns a 50% interest in NRG South Central.

      NRG South Central was formed for the purpose of financing, acquiring, owning, operating and maintaining through its subsidiaries and affiliates the facilities owned by Louisiana Generating and any other facilities that it or its subsidiaries may acquire in the future.

      Pursuant to a competitive bidding process, following the Chapter 11 bankruptcy proceeding of Cajun Electric Power Cooperative, Inc. (“Cajun Electric”), Louisiana Generating acquired the non-nuclear electric power generating assets of Cajun Electric. New Roads was formed for the purpose of holding assets that Louisiana Generating acquired from Cajun Electric which are not necessary for the operation of the newly acquired generating facilities and, with respect to some of these assets, may not be held by Louisiana Generating under applicable federal regulations. Sterlington, which was acquired by NRG Energy and contributed to NRG South Central in August 2000, was formed for the purpose of developing, constructing, owning, and operating an approximately 200 MW simple cycle gas peaking facility in Sterlington, Louisiana. Louisiana Generating purchases the capacity and is entitled to all energy from Sterlington. In December 2000, Sabine River Works LP and Sabine River Works GP acquired a 49% limited partnership interest and a 1% general partnership, respectively, in SRW Cogeneration Limited Partnership, a Delaware Limited Partnership that owns and operates an approximately 450 MW natural gas-fired cogeneration plant located near Orange, Texas. Big Cajun Peaking was formed to develop, construct and own a 238 MW gas-fired peaking generating facility located in New Roads, Louisiana. Bayou Cove was formed to develop, construct and own a 320 MW gas-fired peaking generating facility located in Jennings, Louisiana. Bayou Cove is operated as a merchant power facility.

      On March 31, 2000, for approximately $1,055.9 million, Louisiana Generating acquired 1,708 MW of electric power generation facilities located in New Roads, Louisiana (“Cajun facilities”). The acquisition was financed through a combination of project level long-term debt issued by NRG South Central and equity contributions from NRG South Central’s members. Prior to December 23, 2003, Louisiana Generating was a guarantor of the bonds issued on March 30, 2000, to acquire the Cajun facilities. The acquisition was accounted for under the purchase method of accounting with the aggregate purchase price allocated among the acquired assets and liabilities assumed.

      Pursuant to a project development agreement between NRG Energy and Koch Power, Inc., NRG Energy agreed in April 1999 to participate in the development of an approximately 200 MW simple cycle gas peaking facility in Sterlington, Louisiana. Development of the facility had been commenced by Koch Power’s affiliate, Koch Power Louisiana LLC, a Delaware limited liability company. In August 2000, NRG Energy acquired 100% of Koch Power Louisiana from Koch Power, and renamed it NRG Sterlington Power LLC and contributed the subsidiary to NRG South Central. In August, 2001, the facility became commercially operational.

      Big Cajun I Peaking Power LLC was formed in July 2000 for the purpose of developing, owning and operating an approximately 238 MW simple cycle natural gas peaking facility expansion project at the Big Cajun I site in New Roads, Louisiana. The peaking facility was completed in June 2001. The energy and capacity generated by the expansion project is used to help meet Louisiana Generating’s obligations under the

9

 
NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Cajun facilities’ power purchase agreements, with any excess power and capacity being marketed by NRG Power Marketing.

      During November 2000, NRG Energy acquired a 49% limited partnership interest and a 1% general partnership interest in SRW Cogeneration Limited Partnership (“SRW Cogeneration”) for $15 million and contributed the partnership interests to NRG Sabine River Works LP LLC and NRG Sabine River Works GP LLC, Delaware limited liability companies wholly owned by NRG South Central. SRW Cogeneration completed the facility which became commercially operational in November 2001. The approximately 450 MW natural gas-fired cogeneration plant is located at the DuPont Company’s Sabine River Works petrochemical facility near Orange, Texas. Subsidiaries of Conoco, Inc. own the other 49% and 1% general partnership interests in SRW Cogeneration. On November 5, 2002, the investment in SRW Cogen was sold to Conoco, Inc for a nominal value and the assumption of certain outstanding obligations.

      NRG Bayou Cove LLC was formed in September 2001 for the purpose of developing, owning and operating an approximately 320 MW gas-fired peaking generating facility located near Jennings, Louisiana.

 	Recent Developments	
      On May 14, 2003, NRG Energy and 25 of its direct and indirect wholly owned subsidiaries commenced voluntary petitions under Chapter 11 of the bankruptcy code in the United States Bankruptcy Court for the Southern District of New York. The Company and its direct subsidiaries were included in the Chapter 11 filing. During the bankruptcy proceedings, NRG Energy continued to conduct business and manage the companies as debtors in possession pursuant to sections 1107(a) and 1108 of the bankruptcy code. Two plans of reorganization were filed in connection with the restructuring efforts. The first, filed on May 14, 2003, and referred to as NRG Energy’s Plan of Reorganization, relates to NRG Energy and the other NRG Energy plan debtors. The second plan, relating to the Company, the Northeast Generating subsidiaries and the other South Central subsidiaries, referred to as the Northeast/ South Central Plan of Reorganization, was filed on September 17, 2003. On November 24, 2003, the bankruptcy court entered an order confirming NRG Energy’s Plan of Reorganization and the plan became effective on December 5, 2003. On November 25, 2003, the bankruptcy court issued an order confirming the Northeast/ South Central Plan of Reorganization and the plan became effective on December 23, 2003. In connection with NRG Energy’s emergence from bankruptcy, NRG Energy adopted fresh start reporting in accordance with AICPA Statement of Position 90-7, Financial Reporting by Entities in Reorganization Under the Bankruptcy Code  (“SOP 90-7”) on December 5, 2003. NRG Energy’s fresh start reporting was applied to the Company on a push down accounting basis with the financial statement impact recorded as an adjustment to the December 6, 2003, members’ equity in the amount of $416.4 million.

 	NRG Energy Plan of Reorganization	
      NRG Energy’s Plan of Reorganization is the result of several months of intense negotiations among NRG Energy, Xcel Energy, Inc. (Xcel Energy) and the two principal committees representing NRG Energy creditor groups, referred to as the Global Steering Committee and the Noteholder Committee. A principal component of NRG Energy’s Plan of Reorganization is a settlement with Xcel Energy in which Xcel Energy agreed to make a contribution consisting of cash (and, under certain circumstances, its stock) in the aggregate amount of up to $640 million to be paid in three separate installments following the effective date of NRG Energy’s Plan of Reorganization. The Xcel Energy settlement agreement resolves any and all claims existing between Xcel Energy and NRG Energy and/or its creditors and, in exchange for the Xcel Energy contribution, Xcel Energy is receiving a complete release of claims from NRG Energy and its creditors, except for a limited number of creditors who have preserved their claims as set forth in the confirmation order entered on November 24, 2003.

10

 
NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 	Northeast/ South Central Plan of Reorganization	
      The Northeast/ South Central Plan of Reorganization was proposed on September 17, 2003, after necessary financing commitments were secured. On November 25, 2003, the bankruptcy court issued an order confirming the Northeast/ South Central Plan of Reorganization and the plan became effective on December 23, 2003. In connection with the order confirming the Northeast/ South Central Plan of Reorganization, the court entered a separate order which provides that the allowed amount of the bondholders’ claims shall equal in the aggregate the sum of (i) $1.3 billion plus (ii) any accrued and unpaid interest at the applicable contract rates through the date of payment to the indenture trustee plus (iii) the reasonable fees, costs or expenses of the collateral agent and indenture trustee (other than reasonable professional fees incurred from October 1, 2003) plus (iv) $19.6 million, ratably, for each holder of bonds based upon the current outstanding principal amount of the bonds and irrespective of (a) the date of maturity of the bonds, (b) the interest rate applicable to such bonds and (c) the issuer of the bonds.

      The creditors of Northeast and South Central subsidiaries were unimpaired by the Northeast/ South Central Plan of Reorganization. The creditors holding allowed general secured claims were paid in cash, in full on the effective date of the Northeast/ South Central Plan of Reorganization. Holders of allowed unsecured claims will receive or have received either (i) cash equal to the unpaid portion of their allowed unsecured claim, (ii) treatment that leaves unaltered the legal, equitable and contractual rights to which such unsecured claim entitles the holder of such claim, (iii) treatment that otherwise renders such unsecured claim unimpaired pursuant to section 1124 of the bankruptcy code or (iv) such other, less favorable treatment that is confirmed in writing as being acceptable to such holder and to the applicable debtor.

2.	Summary of Significant Accounting Policies	

 	Principles of Consolidation	
      The consolidated financial statements include the accounts of the Company and its subsidiaries. All significant intercompany transactions and balances have been eliminated in consolidation. Accounting policies for all of the Company’s operations are in accordance with the accounting principles generally accepted in the United States of America.

 	NRG Energy Fresh Start Reporting/Push Down Accounting	
      In accordance with SOP 90-7, certain companies qualify for fresh start (“Fresh Start”) reporting in connection with their emergence from bankruptcy. Fresh Start reporting is appropriate on the emergence from Chapter 11 if the reorganization value of the assets of the emerging entity immediately before the date of confirmation is less than the total of all post-petition liabilities and allowed claims, and if the holders of existing voting shares immediately before confirmation receive less than 50% of the voting shares of the emerging entity. NRG Energy met these requirements and adopted Fresh Start reporting and applied push down accounting to its various subsidiary operations including the Company. Under push down accounting, the Company’s equity fair value was allocated to the Company’s assets and liabilities based on their estimated fair values as of December 5, 2003, as further described in Note 3.

      Under the requirements of Fresh Start, NRG Energy adjusted its assets and liabilities, other than deferred income taxes, to their estimated fair values as of December 5, 2003. As a result of marking the assets and liabilities to their estimated fair values, NRG Energy determined that there was a negative reorganization value that was reallocated back to the tangible and intangible assets. Deferred taxes were determined in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 109,  Accounting for Income Taxes . The net effect of all Fresh Start adjustments resulted in a gain of $3.9 billion, which is reflected in NRG Energy’s Predecessor Company results for the period from January 1, 2003 to December 5, 2003. The

11

 
NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

application of the Fresh Start provisions of SOP 90-7 created a new reporting entity having no retained earnings or accumulated deficit.

      As part of the bankruptcy process, NRG Energy engaged an independent financial advisor to assist in the determination of its reorganized enterprise value. The fair value calculation was based on management’s forecast of expected cash flows from its core assets. Management’s forecast incorporated forward commodity market prices obtained from a third party consulting firm. A discounted cash flow calculation was used to develop the enterprise value of Reorganized NRG, determined in part by calculating the weighted average cost of capital of the Reorganized NRG. The Discounted Cash Flow, (“DCF,”) valuation methodology equates the value of an asset or business to the present value of expected future economic benefits to be generated by that asset or business. The DCF methodology is a “forward looking” approach that discounts expected future economic benefits by a theoretical or observed discount rate. The independent financial advisor prepared a 30-year cash flow forecast using a discount rate of approximately 11%. The resulting reorganization enterprise value as included in the Disclosure Statement ranged from $5.5 billion to $5.7 billion. The independent financial advisor then subtracted NRG Energy’s project level debt and made several other adjustments to reflect the values of assets held for sale, excess cash and collateral requirements to estimate a range of Reorganized NRG equity value of between $2.2 billion and $2.6 billion.

      In constructing the Fresh Start balance sheet upon emergence from bankruptcy, NRG Energy used a reorganization equity value of approximately $2.4 billion, as NRG Energy believed this value to be the best indication of the value of the ownership distributed to the new equity owners. NRG Energy’s Plan of Reorganization provided for the issuance of 100,000,000 shares of NRG Energy common stock to the various creditors resulting in a calculated price per share of $24.04. The reorganization value of approximately $9.1 billion was determined by adding the reorganized equity value of $2.4 billion, $3.7 billion of interest bearing debt and other liabilities of $3.0 billion. The reorganization value represents the fair value of an entity before liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after restructuring. This value is consistent with the voting creditors and Court’s approval of NRG Energy’s Plan of Reorganization.

      The application of SOP 90-7 and push down accounting resulted in the creation of a new reporting entity for the Company. Consequently, the consolidated financial statements of the Reorganized Company and the Predecessor Company are separated by a black line to distinguish that the assets, liabilities and equity as well as the results of operations are not comparable between periods. Under the requirements of push down accounting, the Company has adjusted its assets and liabilities to their estimated fair values as of December 5, 2003. The impact of push down accounting resulted in the reduction of members’ equity for the Company in the amount of $416.4 million.

      Between May 14, 2003 and December 23, 2003, the Company operated as a debtor in possession under the supervision of the bankruptcy court. The consolidated financial statements for reporting periods within that timeframe were prepared in accordance with the provisions of SOP 90-7.

      For financial reporting purposes, close of business on December 5, 2003, represents the date of NRG Energy’s emergence from bankruptcy. As previously stated, the Company and certain of its subsidiaries emerged from bankruptcy on December 23, 2003. The accompanying consolidated financial statements reflect

12

 
NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

the impact of NRG Energy’s emergence from bankruptcy effective December 5, 2003. As used herein, the following terms refer to the Company and its operations:
 	 	 	
“Predecessor Company”	 	The Company, prior to push down accounting	
 	 	The Company’s operations, January 1, 2001-December 31, 2001	
 	 	The Company’s operations, January 1, 2002-December 31, 2002	
 	 	The Company’s operations, January 1, 2003-December 5, 2003	
 	
“Reorganized Company”	 	The Company, post push down accounting	
 	 	The Company’s operations, December 6, 2003-December 31, 2003	
      The bankruptcy court in its confirmation order approved NRG Energy’s Plan of Reorganization on November 24, 2003, and subsequently approved the Company’s Plan of Reorganization on December 23, 2003. Under the requirements of SOP 90-7, the Fresh Start date is determined to be the confirmation date unless significant uncertainties exist regarding the effectiveness of the bankruptcy order. NRG Energy’s Plan of Reorganization required completion of the Xcel Energy settlement agreement prior to emergence from bankruptcy. Management believes this settlement agreement was a significant contingency and thus delayed the Fresh Start date until the Xcel Energy settlement agreement was finalized on December 5, 2003.

 	Cash and Cash Equivalents	
      Cash and cash equivalents include highly liquid investments with a maturity of three months or less at the time of purchase.

 	Restricted Cash	
      Restricted cash consists primarily of funds held in trust accounts to satisfy the requirements of certain debt agreements. The restricted cash balance was $0.1 million, $133.8 million and $109.3 million at December 31, 2003, December 6, 2003 and December 31, 2002, respectively.

 	Inventory	
      Inventory consisting of coal, spare parts and fuel oil is valued at the lower of weighted average cost or market.

 	Property, Plant and Equipment	
      Property, plant and equipment are stated at cost; however, impairment adjustments are recorded whenever events or changes in circumstances indicate carrying values may not be recoverable. At December 5, 2003, the Company recorded adjustments to the property, plant and equipment to reflect such items at fair value in accordance with push down accounting. A new cost basis was established with these adjustments. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance that do not improve or extend the life of the respective asset are charged to expense as incurred. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. The assets and related accumulated depreciation amounts are adjusted for asset retirements and disposals with the resulting gain or loss included in operations.

 	Asset Impairments	
      Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate carrying values may not be recoverable. Such reviews were performed in accordance

13

 
NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. An impairment loss is recognized if the total future estimated undiscounted cash flows expected from an asset is less than its carrying value. An impairment charge is measured by the difference between an asset’s carrying amount and fair value. Fair values are determined by a variety of valuation methods, including appraisals, sales prices of similar assets and present value techniques.

      Investments accounted for by the equity method are reviewed for impairment in accordance with APB Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock  (“APB Opinion No. 18”). APB Opinion No. 18 requires that a loss in value of an investment that is other than a temporary decline should be recognized. The Company identifies and measures loss in value of equity investments based upon a comparison of fair value to carrying value.

 	Capitalized Interest	
      Interest incurred on funds borrowed to finance projects expected to require more than three months to complete is capitalized. Capitalization of interest is discontinued when the asset under construction is ready for its intended use or when a project is terminated or construction ceased. No capitalized interest was recorded during the period from December 6, 2003 to December 31, 2003 or the period from January 1, 2003 to December 5, 2003. Capitalized interest was approximately $6.3 million during the year ended December 31, 2002, and no capitalized interest was recorded during the year ended December 31, 2001.

 	Debt Issuance Costs	
      Debt issuance costs consist of legal and other costs incurred to obtain debt financing. These costs, which were written off as part of push down accounting (see Note 3), were capitalized and amortized as interest expense on a basis which approximates the effective interest method over the terms of the related debt.

 	Intangible Assets	
      Intangible assets represent contractual rights held by the Company. Intangible assets are amortized over their economic useful life and reviewed for impairment on a periodic basis.

      Intangible assets consist primarily of the fair value of power sales agreements and emission allowances. The amounts related to the power sales agreements will be amortized as a reduction to revenue over the terms and conditions of each contract. Emission allowance related amounts will be amortized as additional fuel expense based upon the actual level of emissions from the respective plant through 2023.

      Effective January 1, 2002, the Company implemented SFAS No. 142, Goodwill and Other Intangible Assets. Pursuant to SFAS No. 142, goodwill is not amortized but is subject to periodic testing. At December 31, 2003, December 6, 2003 and December 31, 2002, the Company had no goodwill recorded in the consolidated financial statements.

 	Burdensome Contracts	
      As part of push down accounting, the Company recognized liabilities for executory contracts (power sales agreements) related to the sale of electric capacity and energy in future periods, where the fair value was determined to be significantly burdensome as compared to market expectations. These liabilities represent the out-of-market portion of the executory contracts and are not an indication of the entire fair value of the contracts. Therefore, the liability is being amortized as an increase to revenue over the terms and conditions of each underlying contract. The amount is included on the consolidated balance sheets in other long-term obligations.

14

 
NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 	Revenue Recognition	
      Revenues from the sale of electricity are recorded based upon the output delivered and capacity provided at rates specified under contract terms or prevailing market rates. Under fixed-price contracts, revenues are recognized as products or services are delivered. Revenues and related costs under cost reimbursable contract provisions are recorded as costs are incurred. Capacity and ancillary revenue is recognized when contractually earned. Disputed revenues are not recorded in the financial statements until disputes are resolved and collection is assured.

      The equity method of accounting is applied to investments in partnerships, because the ownership structure prevents the Company from exercising a controlling influence over operating and financial policies of the projects. Under this method, equity in pretax income or losses are reflected as equity in earnings of unconsolidated affiliates.

 	Power Marketing Activities	
      NRG South Central and certain of its subsidiaries have entered into an agency agreement with a marketing affiliate for the sale of energy, capacity and ancillary services produced and the procurement and management of fuel and emission allowances, which enables the affiliate to engage in forward purchases, sales and hedging transactions to manage the Company’s electricity price exposure. Net gains or losses on hedges by the marketing affiliate, which are physically settled, are recognized in the same manner as the hedged item. The Company receives the net transaction price on all contracts that are physically settled by its marketing affiliate.

 	Income Taxes	
      The Company has been organized as a limited liability company. Therefore, federal and state income taxes are assessed at the member level. However, a provision for separate company federal and state income taxes has been reflected in the accompanying consolidated financial statements (see Note 21 — Income Taxes). As a result of the Company being included in the NRG Energy consolidated tax return and tax payments, federal and state taxes payable amounts resulting from the tax provision are reflected as a contribution by members in the consolidated statement of members’ equity and consolidated balance sheet.

      Deferred income taxes are recognized for the tax consequences in future years of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts at each year end based on enacted tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. Income tax expense is the tax payable for the period and the change during the period in deferred tax assets and liabilities. A valuation allowance is recorded to reduce deferred tax assets to the amount more likely than not to be realized.

 	Concentrations of Credit Risk	
      Financial instruments, which potentially subject the Company to concentrations of credit risk, consist primarily of cash, accounts receivable, notes receivable and investments in debt securities. Cash accounts are generally held in federally insured banks. Accounts receivable, notes receivable and derivative instruments are concentrated within entities engaged in the energy industry. These industry concentrations may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. Receivables are generally not collateralized; however, the Company believes the credit risk posed by industry concentration is offset by the diversification and credit worthiness of its customer base.

15

 
NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 	Fair Value of Financial Instruments	
      The carrying amount of cash and cash equivalents, receivables, accounts payables, and accrued liabilities approximate fair value because of the short maturity of these instruments. The fair value of long-term debt is estimated based on quoted market prices and similar instruments with equivalent credit quality.

 	Use of Estimates in Financial Statements	
      The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenue and expenses during the reporting period. Actual results may differ from those estimates.

      In recording transactions and balances resulting from business operations, the Company uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, uncollectible accounts and the valuation of long-term energy commodities contracts, among others. In addition, estimates are used to test long-lived assets for impairment and to determine fair value of impaired assets. As better information becomes available (or actual amounts are determinable), the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

 	Reclassifications	
      Certain prior year amounts have been reclassified for comparative purposes. These reclassifications had no effect on net income or total members’ equity as previously reported.

3.	Emergence from Bankruptcy and Fresh Start Reporting	
      In accordance with the requirements of push down accounting, the Company’s fair value of $30.2 million was allocated to the Company’s assets and liabilities based on their individual estimated fair values. A third party was used to complete an independent appraisal of the Company’s tangible assets, intangible assets and contracts.

      The determination of the fair value of the Company’s assets and liabilities was based on a number of estimates and assumptions, which are inherently subject to significant uncertainties and contingencies.

      Due to the adoption of push down accounting as of December 5, 2003, the Reorganized Company’s consolidated balance sheets, consolidated statements of operations and cash flows have not been prepared on a consistent basis with the Predecessor Company’s consolidated financial statements and are not comparable in certain respects to the consolidated financial statements prior to the application of push down accounting. A black line has been drawn on the accompanying consolidated financial statements to separate and distinguish

16

 
NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

between the Reorganized Company and the Predecessor Company. The effects of the push down accounting adjustments on the Company’s consolidated balance sheet as of December 5, 2003, were as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor	 	 	 	Reorganized	
 	 	Company	 	 	 	Company	

	 	 	 	

	
 	 	December 5,	 	Push Down	 	December 6,	
 	 	2003	 	Adjustments	 	2003	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
ASSETS	
Current assets	 	 	 	 	 	 	 	 	 	 	 	 	
 	Cash and cash equivalents	 	$	11,398	 	 	$	—	 	 	$	11,398	 	
 	Restricted cash	 	 	133,793	 	 	 	—	 	 	 	133,793	 	
 	Accounts receivable	 	 	37,753	 	 	 	—	 	 	 	37,753	 	
 	Accounts receivable — affiliates	 	 	4,751	 	 	 	—	 	 	 	4,751	 	
 	Notes receivable	 	 	1,500	 	 	 	—	 	 	 	1,500	 	
 	Inventory	 	 	47,970	 	 	 	(7,547	)(A)	 	 	40,423	 	
 	Prepayments and other current assets	 	 	8,647	 	 	 	—	 	 	 	8,647	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total current assets	 	 	245,812	 	 	 	(7,547	)	 	 	238,265	 	
Property, plant and equipment, net	 	 	1,102,151	 	 	 	(184,978	)(B)	 	 	917,173	 	
Decommissioning fund investments	 	 	4,809	 	 	 	—	 	 	 	4,809	 	
Intangible assets	 	 	1,605	 	 	 	120,174	 (C)	 	 	121,779	 	
Debt issuance costs, net	 	 	19,330	 	 	 	(19,330	)(D)	 	 	—	 	
Other assets	 	 	663	 	 	 	2,426	 (E)	 	 	3,089	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total assets	 	$	1,374,370	 	 	$	(89,255	)	 	$	1,285,115	 	

	 	 	 	

	 	 	 	

	 	
 	
LIABILITIES AND MEMBERS’ EQUITY	
Current liabilities	 	 	 	 	 	 	 	 	 	 	 	 	
 	Current portion of long-term debt	 	$	856,241	 	 	$	(24,000	)(D)	 	$	832,241	 	
 	Accounts payable	 	 	15,279	 	 	 	—	 	 	 	15,279	 	
 	Accrued interest	 	 	22,221	 	 	 	—	 	 	 	22,221	 	
 	Other current liabilities	 	 	32,764	 	 	 	—	 	 	 	32,764	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total current liabilities	 	 	926,505	 	 	 	(24,000	)	 	 	902,505	 	
Burdensome contracts	 	 	—	 	 	 	342,210	 (C)	 	 	342,210	 	
Other long-term obligations	 	 	1,306	 	 	 	8,885	 (C)	 	 	10,191	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total liabilities	 	 	927,811	 	 	 	327,095	 	 	 	1,254,906	 	

	 	 	 	

	 	 	 	

	 	
Members’ equity	 	 	 	 	 	 	 	 	 	 	 	 	
Members’ contributions	 	 	585,040	 	 	 	(554,831	)	 	 	30,209	 	
Accumulated net loss	 	 	(138,481	)	 	 	138,481	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total members’ equity	 	 	446,559	 	 	 	(416,350	)(F)	 	 	30,209	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total liabilities and members’ equity	 	$	1,374,370	 	 	$	(89,255	)	 	$	1,285,115	 	

	 	 	 	

	 	 	 	

	 	

 
 	 	 	
(A)	 	Accounting policy change upon adoption of push down accounting. Consumables are no longer included as inventory and are expensed as incurred.	
17

 
NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(B)	 	Result of allocating the equity value in conformity with the purchase method of accounting for business combinations. These allocations were based on valuations obtained from independent appraisers.	
 	 	 	
(C)	 	Reflects management’s estimate, with the assistance of independent appraisers, of the fair value of power sales agreements and SO2 emission credits. Management identified certain power sales agreements that were either significantly valuable or significantly burdensome as compared to our market expectations. In addition, the Asset Retirement Obligation (“ARO”) was revalued.	
 	 	 	
(D)	 	Revaluation of debt to fair value.	
 	 	 	
(E)	 	Adjustments resulting from the Company’s bankruptcy settlement.	
 	 	 	
(F)	 	The change in members’ equity reflects the fair value adjustment resulting from NRG Energy’s Fresh Start accounting procedures.	

4.	Other Charges	
      Restructuring, impairment charges and reorganization items included in operating costs and expenses in the consolidated statement of operations include the following:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Year	
 	 	2003 to	 	2003 to	 	Ended	
 	 	December 31,	 	December 5,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Reorganization items	 	$	104	 	 	$	31,120	 	 	$	—	 	
Restructuring items and impairment charges	 	 	—	 	 	 	—	 	 	 	139,929	 	

	 	 	 	

	 	 	 	

	 	
 	 	$	104	 	 	$	31,120	 	 	$	139,929	 	

	 	 	 	

	 	 	 	

	 	

 	Reorganization Items	
      In connection with the confirmation of the Northeast/South Central Plan of Reorganization, the debt held at the Company became an allowable claim for the principal amounts of $750.8 million. As a result, the Company incurred a charge of approximately $9.1 million to write-off related debt issuance costs. As part of the refinancing transaction completed in December 2003, the Company incurred a pre-payment charge of approximately $11.3 million. Both items were expensed in November 2003, as they were determined to be an allowed claim. The Company also incurred legal and advisor fees of $11.5 million.

18

 
NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	Predecessor	
 	 	Company	 	Company	

	 	

	
 	 	For the	 	For the	
 	 	Period from	 	Period from	
 	 	December 6,	 	January 1,	
 	 	2003 to	 	2003 to	
 	 	December 31,	 	December 5,	
 	 	2003	 	2003	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Reorganization items	 	 	 	 	 	 	 	 	
 	Deferred financing costs	 	$	—	 	 	$	9,141	 	
 	Pre-payment charges	 	 	—	 	 	 	11,261	 	
 	Legal and advisor fees	 	 	104	 	 	 	11,494	 	
 	Interest earned on accumulated cash	 	 	—	 	 	 	(776	)	

	 	 	 	

	 	
 	 	Total reorganization items	 	$	104	 	 	$	31,120	 	

	 	 	 	

	 	

 	Restructuring and Impairment Charges	
      The credit rating downgrades, defaults under certain credit agreements, increased collateral requirements and reduced liquidity experienced by the Company during the third quarter of 2002 were “triggering events” which, pursuant to SFAS No. 144, required the Company to review the recoverability of its long-lived assets. As a result, the Company determined that Bayou Cove Peaking Power, a wholly owned subsidiary of NRG Bayou Cove, and the turbine generator held at New Roads, became impaired during the third quarter of 2002 and should be written down to fair market value. During 2002, the Company recorded impairment charges of $126.6 million and $12.0 million on NRG Bayou Cove and the turbine generator, respectively.

      To determine whether an asset was impaired, the Company compared the asset carrying values to total future estimated undiscounted cash flows. Separate analyses were completed for assets or groups of assets at the lowest level for which identifiable cash flows were largely independent of the cash flows of other assets and liabilities. The estimates of future cash flow included only future cash flows, net of associated cash outflows, directly associated with and expected to arise as a result or the Company’s assumed use and eventual disposition of the asset. Cash flow estimates associated with assets in service were based on the asset’s existing service potential. The cash flow estimates may include probability weightings to consider possible alternative course of action and outcomes, given the uncertainty of available information and prospective market conditions.

      If an asset was determined to be impaired based on the cash flow testing performed, an impairment loss was recorded to write down the asset to its fair value. Estimates of fair value were based on prices for similar assets and present value techniques. Fair values determined by similar asset prices reflect the Company’s current estimate of recoverability from expected marketing of project assets. For fair values determined by projected cash flows, the fair value represents a discounted cash flow amount over the remaining life of each project that reflects project-specific assumptions for long-term power pool prices, escalated future project operating costs and expected plan operation given assumed market conditions.

      In addition to asset impairment charges, the Company incurred $1.4 million of expected severance costs associated with the combining of various functions and restructuring costs consisting of advisor fees. These costs were also recognized as restructuring and impairment charges in the consolidated statements of operations.

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NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

5.	Inventory	
      Inventory, which is valued at the lower of weighted average cost or market, consists of:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Coal	 	$	26,108	 	 	$	31,342	 	 	$	48,001	 	
Spare parts	 	 	8,207	 	 	 	8,241	 	 	 	15,523	 	
Fuel oil	 	 	783	 	 	 	840	 	 	 	840	 	

	 	 	 	

	 	 	 	

	 	
 	Total inventory	 	$	35,098	 	 	$	40,423	 	 	$	64,364	 	

	 	 	 	

	 	 	 	

	 	

6.	Property, Plant and Equipment	
      The major classes of property, plant and equipment were as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Predecessor	 	 	
 	 	 	 	Reorganized Company	 	Company	 	 	
 	 	Average	 	

	 	

	 	 	
 	 	Remaining	 	December 31,	 	December 6,	 	December 31,	 	Depreciable	
 	 	Useful Life	 	2003	 	2003	 	2002	 	Lives	

	 	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Land	 	 	 	 	 	$	30,935	 	 	$	30,935	 	 	$	15,579	 	 	 	 	 	
Facilities, machinery and equipment	 	 	18 years	 	 	 	885,656	 	 	 	885,656	 	 	 	1,194,138	 	 	 	1-35 years	 	
Office furnishings and equipment	 	 	3 years	 	 	 	582	 	 	 	582	 	 	 	4,433	 	 	 	1-5 years	 	
Construction in progress	 	 	 	 	 	 	329	 	 	 	—	 	 	 	988	 	 	 	 	 	
Accumulated depreciation	 	 	 	 	 	 	(2,561	)	 	 	—	 	 	 	(83,242	)	 	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	 	 	
Property, plant and equipment, net	 	 	 	 	 	$	914,941	 	 	$	917,173	 	 	$	1,131,896	 	 	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	 	 	

7.	Asset Retirement Obligation	
      Effective January 1, 2003, the Company adopted SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires an entity to recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred. Upon initial recognition of a liability for an asset retirement obligation, an entity shall capitalize an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes and written or oral contracts, including obligations arising under the doctrine of promissory estoppel.

      The Company identified certain retirement obligations within its operations. These asset retirement obligations are related primarily to the future dismantlement of equipment on leased property and environment obligations related to ash disposal site closures. The adoption of SFAS No. 143 resulted in recording a $0.3 million increase to property, plant and equipment and a $0.4 million increase to other long-term obligations. The cumulative effect of adopting SFAS No. 143 was recorded as a $21,000 increase to depreciation expense and a $0.1 million increase to operating costs in the period from January 1, 2003 to December 5, 2003, as the Company considered the cumulative effect to be immaterial.

20

 
NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The following represents the balances of the asset retirement obligation at January 1, 2003, and the additions and accretion of the asset retirement obligation for the period from January 1, 2003 to December 5, 2003 and the period from December 6, 2003 to December 31, 2003, which is included in other long-term obligations in the consolidated balance sheets. As a result of applying push down accounting, the Company revalued its asset retirement obligations on December 5, 2003. The Company recorded an additional asset retirement obligation of $2.2 million in connection with push down accounting. This amount results from a change in the discount rate used between adoption and December 5, 2003, equal to 500 to 600 basis points.

 	 	Predecessor Company	

	
 	 	 	 	Accretion	 	 	
 	 	Beginning	 	for Period	 	Adjustment	 	Ending	
 	 	Balance	 	Ended	 	for	 	Balance	
 	 	January 1,	 	December 5,	 	Fresh Start	 	December 5,	
 	 	2003	 	2003	 	Reporting	 	2003	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Asset retirement obligations	 	$	396	 	 	$	57	 	 	$	2,170	 	 	$	2,623	 	

 	 	Reorganized Company	

	
 	 	 	 	Accretion	 	 	
 	 	Beginning	 	for Period	 	Ending	
 	 	Balance	 	December 6 to	 	Balance	
 	 	December 6,	 	December 31,	 	December 31,	
 	 	2003	 	2003	 	2003	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Asset retirement obligations	 	$	2,623	 	 	$	15	 	 	$	2,638	 	
      The following represents the pro forma effect on the Company’s net income for the period from January 1, 2003 to December 5, 2003, and for the years ended December 31, 2002 and 2001, as if the Company had adopted SFAS No. 143 as of January 1, 2001:

 	 	Predecessor Company	

	
 	 	For the	 	 	
 	 	Period from	 	 	
 	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	December 31,	
 	 	December 5,	 	

	
 	 	2003	 	2002	 	2001	

	 	

	 	

	
 	 	 	 	(As Restated)	 	(As Restated)	
 	 	 	
 	 	(In thousands of dollars)	
Net (loss) income as reported	 	$	(27,969	)	 	$	(132,085	)	 	$	6,015	 	
Pro forma adjustment to reflect retroactive adoption of SFAS No. 143	 	 	70	 	 	 	(28	)	 	 	(42	)	

	 	 	 	

	 	 	 	

	 	
Pro forma net (loss) income	 	$	(27,899	)	 	$	(132,113	)	 	$	5,973	 	

	 	 	 	

	 	 	 	

	 	
      On a pro forma basis an asset retirement obligation of $0.4 million would have been recorded as other long-term obligations at both January 1, 2002 and December 31, 2002, based on similar assumptions used to determine the amounts on the Company’s balance sheets at December 31, 2003 and December 6, 2003.

8.	Intangible Assets	
      During the first quarter of 2002, the Company adopted SFAS No. 142, Goodwill and other Intangible Assets, which requires new accounting for intangible assets, including goodwill. Intangible assets with finite lives will be amortized over their economic useful lives and periodically reviewed for impairment. Goodwill will no longer be amortized, but will be tested for impairment annually and on an interim basis if an event occurs or a circumstance changes between annual tests that may reduce the fair value of a reporting unit below

21

 
NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

its carrying value. The Company did not recognize any asset impairments as a result of adopting SFAS No. 142.

 	Reorganized Company	
      The Company had intangible assets with a net carrying value of $121.8 million and $121.0 million at December 6, 2003 and December 31, 2003, respectively. The power sales agreement amounts will be amortized as a reduction to revenue over the terms and conditions of each contract. The remaining amortization period is four years for the power sales agreements. Emission allowances will be amortized as additional fuel expense based upon the actual level of emissions from the respective plants through 2023. No amortization was recorded during the period from December 6, 2003 to December 31, 2003, as this balance includes only emission allowances for 2004 and beyond. All emission allowances for 2003 were used prior to December 5, 2003. The amortization expense for the period from December 6, 2003 to December 31, 2003, was $0.8 million related to power sales agreements. The annual aggregate amortization expense for each of the five succeeding years is expected to approximate $12.6 million in years one through four, and $5.7 million in year five for both the power sales agreements and emission allowances. Intangible assets in the Reorganized Company consisted of the following:

 	 	Reorganized Company	

	
 	 	 	 	 	
 	 	December 31, 2003	 	December 6, 2003	

	 	

	
 	 	Gross	 	 	 	Gross	 	 	
 	 	Carrying	 	Accumulated	 	Carrying	 	Accumulated	
 	 	Amount	 	Amortization	 	Amount	 	Amortization	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Intangible assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Power sales agreements	 	$	27,800	 	 	$	787	 	 	$	27,800	 	 	$	—	 	
 	Emission allowances	 	 	93,979	 	 	 	—	 	 	 	93,979	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total intangible assets	 	$	121,779	 	 	$	787	 	 	$	121,779	 	 	$	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	

 	Predecessor Company	
      At December 31, 2002, the Company had intangible assets of $1.7 million. For the period from January 1, 2003 to December 5, 2003, and for the years ended December 31, 2002 and 2001, the Company recorded approximately $0, $123,000 and $78,000 of amortization expense, respectively. The net amount of the intangible assets was transferred to fixed assets as part of push down accounting.

22

 
NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

9.	Long-Term Debt and Notes Payable — Affiliate	
      NRG South Central’s long-term debt consists of the following:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
NRG South Central senior bonds	 	 	 	 	 	 	 	 	 	 	 	 	
 	Series A — due 2016 — 8.962%	 	$	—	 	 	$	450,750	 	 	$	450,750	 	
 	Series B — due 2024 — 9.429%	 	 	—	 	 	 	300,000	 	 	 	300,000	 	
NRG Peaker — Bayou Cove — note payable affiliate due 2019 — 6.673%	 	 	105,491	 	 	 	105,491	 	 	 	105,491	 	
Unamortized fair value adjustment	 	 	(23,818	)	 	 	(24,000	)	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total debt	 	$	81,673	 	 	$	832,241	 	 	$	856,241	 	

	 	 	 	

	 	 	 	

	 	
      On March 30, 2001, the Company entered into a 364-day, $40 million floating rate working capital revolving credit facility. The Company extended this facility in March 2002 for an additional three months, on substantially similar terms. The Company paid down the outstanding balance in June 2002 with funds received from NRG Energy in an equity contribution, and the facility was not renewed.

      On March 30, 2000, the Company issued $800 million of senior secured bonds in two tranches. The first tranche was for $500 million with a coupon of 8.962% and a maturity of 2016. The second tranche was for $300 million with a coupon of 9.479% and a maturity of 2024. Interest on the bonds is payable in arrears on each March 15 and September 15. Principal payments are made semi-annually on each March 15 and September 15. The proceeds of the bonds were used to finance the Company’s acquisition of the Cajun generating facilities on March 31, 2000. On December 13, 2000, the Company commenced an exchange offer of these bonds with registered bonds that contain similar terms and conditions. The exchange offer was closed on January 19, 2001, with all bonds being exchanged. At December 31, 2003, December 6, 2003 and December 31, 2002, there remained $0, $750.8 million and $750.8 million of outstanding bonds, respectively. On September 15, 2002, the Company missed a $47 million principal and interest payment. The 15-day grace period to make payment related to this issue passed and the Company did not make the required payments. On November 21, 2002, the bond trustee, on behalf of bondholders, accelerated the debt rendering it due and payable. In January 2003, the South Central Generating bondholders unilaterally withdrew $35.6 million from the restricted revenue account, relating to the September 15, 2002, interest payment and fees. On March 17, 2003, South Central bondholders were paid $34.4 million due in relation to the semi-annual interest payment and the $12.8 million principal payment was deferred. NRG South Central remains in default on these notes. As a result, the debt has been classified as current at December 6, 2003 and December 31, 2002.

      As part of the Northeast/ South Central Plan of Reorganization, the Company on December 23, 2003, paid all outstanding bonds, related interest and penalties as part of its emergence from bankruptcy. On December 23, 2003, NRG Energy issued $1.25 billion in Second Priority Notes, due and payable on December 15, 2013. On the same date, NRG Energy also entered into a new credit facility for up to $1.45 billion. Proceeds of the December 23, 2003, Second Priority Note issuance and the New Credit Facility were used, among other things, for repayment of secured debt held by the Company. The Company used proceeds of $632.3 million from a capital contribution from NRG Energy and cash on hand to pay the outstanding balance of $750.8 million, along with $15.3 million in accrued interest and $11.3 million in pre-payment charges.

23

 
NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     Project Level Debt

      On June 18, 2002, NRG Peaker Finance Company LLC (“NRG Peaker”), a wholly owned subsidiary of NRG Energy and an affiliate of the Company, issued $325 million of senior secured bonds. The bonds bear interest at a floating rate equal to three months USD-LIBOR BBA plus 1.07%. Interest on the bonds is payable on March 10, June 10, September 10, and December 10 of each year commencing on September 10, 2002. The Peaker projects which secure the senior secured bonds are a combination of several indirect wholly owned subsidiaries of NRG Energy, which include the following entities: Bayou Cove Peaking Power LLC (“Bayou Cove”), Big Cajun I Peaking Power LLC (“Big Cajun Peaking”), NRG Rockford LLC and Rockford II LLC and NRG Sterlington Power LLC (“Sterlington”). Three of these entities, Bayou Cove, Big Cajun Peaking, and Sterlington, are wholly owned nonguarantor subsidiaries of the Company. NRG Peaker Finance Company LLC advanced unsecured loans in the amounts of $107.4 million to Bayou Cove through project loan agreements. The project owners used the gross proceeds of the loans to (1) reimburse NRG Energy for construction and/or acquisition costs for the peaker projects previously paid by NRG Energy, (2) pay to XL Capital Assurance (“XLCA”) the premium for the Bond Policy, (3) provide funds to NRG Peaker to collateralize a portion of NRG Energy’s contingent guaranty obligations and (4) pay transaction costs incurred in connection with the offering of the bonds (including reimbursement of NRG Energy for the portion of such costs previously paid by NRG Energy). At December 31, 2003, December 6, 2003, and December 31, 2002, Bayou Cove, had an affiliate loan outstanding in the amount of $105.5 million at each date in connection with the NRG Peaker bonds. The note bears a fixed interest rate of 6.673%. On the maturity date of June 10, 2019, the principal and accrued interest is due. As of December 31, 2002, NRG Peaker bonds were in default; therefore, the affiliate loan outstanding has been classified as current as of December 31, 2002. Pursuant to the issuance of the bonds, approximately $21.2 million of debt issuance costs were allocated to Bayou Cove, Big Cajun Peaking and Sterlington. These costs represent prepayment of a credit insurance policy (“Bond Policy”) with XLCA. This Bond Policy is a financial guaranty insurance policy that guarantees payment of scheduled principal and interest payments on the bonds.

      The bonds are secured by a pledge of membership interests in NRG Peaker and a security interest in all of its assets, which initially consisted of notes evidencing loans to the affiliate project owners, including Bayou Cove, Big Cajun Peaking and Sterlington. The project owners’ jointly and severally guarantied the entire principal amount of the bonds and interest on such principal amount. The project owner guaranties are secured by a pledge of the membership interest in three of five project owners, including Bayou Cove, and a security interest in substantially all of the project owners’ assets related to the peaker projects, including equipment, real property rights, contracts and permits. NRG Energy has entered into a contingent guaranty agreement in favor of the collateral agent for the benefit of the secured parties, under which it agreed to make payments to cover scheduled principal and interest payments on the bonds and regularly scheduled payments under the interest rate swap agreement, to the extent that the net revenues from the peaker projects are insufficient to make such payments, in specified circumstances. This financing contains a cross-default provision related to the failure by NRG Energy to make payment of principal, interest or other amounts due on debt for borrowed money in excess of $50 million of payment defaults by NRG Energy, a covenant that was violated in October 2002. In addition, liens were placed against the Bayou Cove facility resulting in an additional default. NRG Peaker is in the process of getting such liens released. On October 22, 2002, XLCA issued a notice on default on the NRG Peaker financing facility. On December 10, 2002, $16.0 million in interest, principal, and swap payments were made from NRG Energy’s restricted cash accounts. As a result, $319.4 million in principal remains outstanding as of December 31, 2002. On May 12, 2003, XLCA accelerated the bonds, rendering the bonds immediately due and payable. Also on May 12, 2003, a forbearance agreement was entered into which forbears XLCA from exercising its rights and remedies.

      On December 10, 2003, $31.1 million in interest, principal, and swap payments were made from restricted cash accounts. As a result, $311.4 million in principal remains outstanding as of December 31, 2003.

24

 
NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      On January 6, 2004, NRG Energy and XLCA consummated a comprehensive restructuring arrangement which provides for, among other things, the provision of a letter of credit by NRG Energy for the benefit of the secured parties in the NRG Peaker financing in lieu of the contingent guarantee described above, the cure or waiver of all defaults under the original financing agreement and the mutual release of claims by the parties. With the exception of distributions to pay taxes, distributions to equity holders are subject to tests regarding NRG Peaker reserve funding and financial ratios.

      In connection with the revaluation of NRG Peaker’s debt to fair value under SOP 90-7, debt discounts were recorded in debt. At December 31, 2003 and December 6, 2003, the unamortized debt discounts recorded in debt were $72.1 million and $72.7 million, respectively. Approximately $23.8 million and $24.0 million of these amounts relate to Bayou Cove at December 31, 2003 and December 6, 2003, respectively.

      In June 2002, NRG Peaker also entered into an interest rate swap agreement pursuant to which it agreed to make fixed rate interest payments and receive floating rate interest payments. The agreement effectively changed the interest exposure on the original $325 million of bonds from LIBOR plus 1.07% (2.24125% at December 31, 2003) to a fixed rate of 6.67%. The interest rate swap counter-party will have a security interest in the collateral for the bonds and the collateral for the Peaker Affiliates’ guarantees. Net payments to be made by NRG Peaker under the interest rate swap agreement will be guaranteed pursuant to a separate financial guaranty insurance policy with XLCA, the issuer of which will have a security interest in the collateral for the bonds and the collateral for the Peaker Affiliates’ guaranties. NRG Peaker was in compliance with this agreement at December 31, 2003. The agreement expires in June 2019.

10.	Derivative Instruments and Hedging Activity	
      On January 1, 2001, the Company adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 137, SFAS No. 138 and SFAS No. 149. SFAS No. 133 requires the Company to record all derivatives on the consolidated balance sheet at fair value. Changes in the fair value of nonhedge derivatives will be immediately recognized in earnings. The criteria used to determine if hedge accounting treatment is appropriate are (a) the designation of the hedge to an underlying exposure, (b) whether or not the overall risk is being reduced and (c) if there is high degree of correlation between the value of the derivative instrument and the underlying obligation. Formal documentation of the hedging relationship, the nature of the underlying risk, the risk management objective, and the means by which effectiveness will be assessed is created at the inception of the hedge. Changes in fair values of derivatives accounted for as hedges are either recognized in earnings as offsets to the changes in fair value of related hedged assets, liabilities and firm commitments or for forecasted transactions, deferred and recorded as a component of accumulated other comprehensive income (“OCI”) until the hedged transactions occur and are recognized in earnings. The ineffective portion of a hedging derivative instrument’s change in fair value is immediately recognized in earnings. The Company also formally assesses, both at inception and at least quarterly thereafter, whether the derivatives used in hedging transactions are highly effective in offsetting the changes in either the fair value or cash flows of the hedged item. This assessment includes all components of each derivative’s gains or losses unless otherwise noted. When it is determined that a derivative ceases to be a highly effective hedge, hedge accounting is discontinued.

     Energy and Energy Related Commodities

      The Company is exposed to commodity price variability in electricity, emission allowance, natural gas, oil and coal used to meet fuel requirements. In order to manage these commodity price risks, the Company entered into transactions for physical delivery of particular commodities for a specific period. These financial instruments are used to hedge physical deliveries, which may take the form of fixed price, floating price or

25

 
NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

indexed sales or purchases, and options, such as puts, calls, basis transactions and swaps. These transactions are utilized to:
 	 	 	
 	• 	Manage and hedge its fixed-price purchases and sales commitments;	
 	 	 	
 	• 	Reduce its exposure to the volatility of spot market prices;	
 	 	 	
 	• 	Hedge fuel requirements at its generation facilities; and	
 	 	 	
 	• 	Protect its investment in fuel inventories.	
     Interest Rates

      From time to time, the Company may use interest rate hedging instruments to protect it from an increase in the cost of borrowings. At December 31, 2003, December 6, 2003 and December 31, 2002, respectively, there were no such instruments outstanding.

      SFAS No. 133 applies to the Company’s long-term power sales contracts, long-term gas purchase contracts and other energy related commodities financial instruments used to mitigate variability in earnings due to fluctuations in spot market prices, hedge fuel requirements at generation facilities and protect investments in fuel inventories. At December 31, 2003, the Company had various commodity contracts extending through 2005. None of these contracts are designated as hedging instruments.

      The adoption of SFAS No. 133 on January 1, 2001, resulted in an after-tax unrealized gain of $0.5 million related to previously deferred net gains on derivatives designated as hedges. During the year ended December 31, 2001, the Company reclassified gains of $0.5 million from OCI to current-period earnings. The Company has no derivative instruments classified as hedges and no deferred gains or losses in OCI at December 31, 2003, December 6, 2003 or December 31, 2002.

     Statement of Operations

      The following tables summarize the effects of SFAS No. 133 on the Company’s statements of operations for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003, and for the years ended December 31, 2002 and 2001, respectively:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Revenues	 	$	(72	)	 	$	(112	)	 	$	92	 	 	$	21	 	
Cost of operations	 	 	—	 	 	 	135	 	 	 	(97	)	 	 	(39	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Total statement of operations impact before tax	 	$	(72	)	 	$	23	 	 	$	(5	)	 	$	(18	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
      During the period from December 6, 2003 to December 31, 2003 and the period from January 1, 2003 to December 5, 2003, the Company recognized no gain or loss due to the ineffectiveness of commodity cash flow hedges, and no components of NRG South Central’s derivative instruments gains or losses were excluded from the assessment of effectiveness.

      The Company’s earnings were decreased for the period from December 6, 2003 to December 31, 2003, and were increased for the period from January 1, 2003 to December 5, 2003, by $72,000 and $23,000,

26

 
NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

respectively, associated with the changes in fair value of energy related derivative instruments not accounted for as hedges in accordance with SFAS No. 133

      During the years ended December 31, 2002 and 2001, respectively, the Company recognized no gain or loss due to ineffectiveness of commodity cash flow hedges, and no components of the Company’s derivative instruments’ gains or losses were excluded from the assessment of effectiveness.

      The Company’s earnings for the years ended December 31, 2002 and 2001, were decreased by unrealized losses of $5,000 and $18,000, respectively, associated with changes in the fair value of energy related derivative instruments not accounted for as hedges in accordance with SFAS No. 133.

11.	Financial Instruments	
      The estimated fair values of the Company’s recorded financial instruments are as follows:

 	 	Reorganized Company	 	Predecessor Company	

	 	

	
 	 	 	 	 	 	 	
 	 	December 31, 2003	 	December 6, 2003	 	December 31, 2002	

	 	

	 	

	
 	 	Carrying	 	Fair	 	Carrying	 	Fair	 	Carrying	 	Fair	
 	 	Amount	 	Value	 	Amount	 	Value	 	Amount	 	Value	

	 	

	 	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Cash	 	$	4,612	 	 	$	4,612	 	 	$	11,398	 	 	$	11,398	 	 	$	310	 	 	$	310	 	
Restricted cash	 	 	99	 	 	 	99	 	 	 	133,793	 	 	 	133,793	 	 	 	109,336	 	 	 	109,336	 	
Notes receivable	 	 	584	 	 	 	584	 	 	 	1,500	 	 	 	1,500	 	 	 	3,000	 	 	 	3,000	 	
Decommissioning funds	 	 	4,809	 	 	 	4,809	 	 	 	4,809	 	 	 	4,809	 	 	 	4,617	 	 	 	4,617	 	
Long-term debt, including current portion	 	 	—	 	 	 	—	 	 	 	750,750	 	 	 	750,750	 	 	 	750,750	 	 	 	525,525	 	
Note payable — affiliate	 	 	81,673	 	 	 	81,673	 	 	 	81,491	 	 	 	81,491	 	 	 	105,491	 	 	 	105,491	 	
      For cash and cash equivalents and restricted cash, the carrying amount approximates fair value because of the short-term maturity of those instruments. The fair value of notes receivable approximates carrying value as the underlying instruments have a variable market interest rate. The fair value of note payable — affiliate and long-term debt is estimated based on the quoted market prices for these issues with similar credit quality. Decommissioning fund investments are comprised of various debt securities of the United States and are carried at amortized cost, which approximates their fair value.

12.	Related Party Transactions	
      The Company and certain of its subsidiaries entered into a power sales and agency agreement with NRG Power Marketing Inc., a wholly owned subsidiary of NRG Energy. The agreement is effective until December 31, 2030. Under the agreement, NRG Power Marketing Inc. (“NRG Power Marketing”) will (i) have the exclusive right to manage, market and sell all power not otherwise sold or committed to or by NRG South Central or its subsidiaries, (ii) procure and provide to the Company and certain of its subsidiaries all fuel required to operate its respective facilities and (iii) market, sell and purchase all emission credits owned, earned or acquired by the Company and certain of its subsidiaries. In addition, NRG Power Marketing will have the exclusive right and obligation to direct the power output from the facilities.

      Under the agreement, NRG Power Marketing pays to the Company and certain of its subsidiaries gross receipts generated through sales, less costs incurred by NRG Power Marketing relative to its providing services (e.g. transmission and delivery costs, fuel cost, taxes, employee labor, contract services, etc.). The Company incurs no fees related to these power sales and agency agreements with NRG Power Marketing.

      The Company and certain of its subsidiaries entered into an operation and maintenance agreement with NRG Operating Services, Inc. (“NRG Operating Services”), a wholly owned subsidiary of NRG Energy.

27

 
NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The agreement is perpetual in term until terminated in writing by the Company or its subsidiaries or until earlier terminated upon an event of default. Under the agreement, at the request of the Company and certain of its subsidiaries, NRG Operating Services manages, oversees and supplements the operation and maintenance of the Cajun facilities.

      During the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003, and for the years ended December 31, 2002 and 2001, the Company and its subsidiaries incurred no operating costs from NRG Operating Services.

      The Company entered into an agreement with NRG Energy for corporate support and services. The agreement is perpetual in term until terminated in writing by the Company or until earlier terminated upon an event of default. Under the agreement, NRG Energy will provide services, as requested, in areas such as human resources, accounting, finance, treasury, tax, office administration, information technology, engineering, construction management, environmental, legal and safety. Under the agreement, NRG Energy is paid for personnel time as well as out-of-pocket costs. These costs are reflected in general and administrative expenses in the consolidated statements of operations.

      During the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003, and for the years ended December 31, 2002 and 2001, the Company incurred approximately $1.2 million, $3.4 million, $0.8 million and $0.6 million, respectively, for corporate support and services.

      At December 31, 2003, December 6, 2003 and December 31, 2002, the Company has an accounts payable — affiliates balance of approximately $0, $0 and $126.5 million, respectively, which consisted primarily of a payable to NRG Energy for capitalized development costs incurred prior to the acquisition of the Cajun facilities, construction costs related to Bayou Cove and operating expenses paid on behalf of the Company as described in the paragraphs above.

      During 2002, in connection with the Peaker financing, Louisiana Generating sold 50% of its interest in the natural gas line to Big Cajun 1 Peaker at a gain of $0.4 million. The intercompany gain was eliminated in consolidation.

13.	Benefits Disclosures	
      Louisiana Generating, a wholly owned subsidiary of the Company, retained a number of the administrative and operating personnel of Cajun Electric upon acquisition of Cajun Electric’s generating facilities. Prior to March 31, 2000, these employees were participants in the National Rural Electric Cooperative Association’s Retirement and Security Program, a master multiple-employer defined benefit plan. Effective March 31, 2000, the Cooperative’s defined benefit and 401-K plans were terminated and no pension obligation was assumed by Louisiana Generating, NRG Energy or the Company. Louisiana Generating sponsors a cash balance pension plan arrangement whereby the employees are entitled to a pension benefit of approximately 7% of total payroll. The employees are also eligible to participate in a 401-K plan that provides for the matching of specified amounts of employee contributions to the plan.

      For the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001, the Company recorded approximately $138,800, $769,700 and $357,000, respectively, of pension expense and approximately $28,500, $460,100 and $680,800, respectively, of 401-K matching funds.

14.	Sales to Significant Customers	
      For the period from December 6, 2003 to December 31, 2003, sales to two customers, Southwest Louisiana Electric Membership Corporation and Dixie Electric Membership Corporation, accounted for

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17.6% and 17.5%, respectively of the Company’s total revenues. For the period from January 1, 2003 to December 5, 2003, sales to two customers, Southwest Louisiana Electric Membership Corporation and Dixie Electric Membership Corporation, accounted for 18.3% and 17.5%, respectively of the Company’s total revenues. For the year ended December 31, 2002, sales to two customers, Southwest Louisiana Electric Membership Corporation and Dixie Electric Membership Corporation, accounted for 16.9% and 15.9%, respectively of the Company’s total revenues. For the year ended December 31, 2001, sales to two customers accounted for 32.1% of the Company’s total revenues, Southwest Louisiana Electric Membership Corporation (16.4%) and Dixie Electric Membership Corporation (15.7%). During March 2000, NRG South Central entered into certain power sales agreements with eleven distribution cooperatives that were customers of Cajun Electric prior to its acquisition of the Cajun facilities. The initial terms of these agreements provide for the sale of energy, capacity and ancillary services for the periods ranging from 4 to 25 years. In addition, NRG South Central assumed Cajun Electric’s obligations under four long-term power supply agreements. The terms of these agreements range from 10 to 26 years. These power sales agreements accounted for 86.7%, 84.9%, 80.8% and 78.4% of the Company’s total revenues during the periods December 6, 2003 to December 31, 2003, January 1, 2003 to December 5, 2003, and for the years ended December 31, 2002 and December 31, 2001, respectively (see Note 15).

15.	Commitments and Contingencies	

 	Operating Lease Commitments	
      The Company leases certain of its land, storage space and equipment under operating leases expiring on various dates through 2015. Rental expense under these operating leases was approximately $27,000, $0.5 million and $0.5 million for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 and the year ended December 31, 2002, respectively. Future minimum lease commitments under these leases for the years ending after December 31, 2003, are as follows:
 	 	 	 	 	
 	 	(In thousands	
 	 	of dollars)	
2004	 	$	181	 	
2005	 	 	55	 	
2006	 	 	23	 	
2007	 	 	20	 	
2008	 	 	20	 	
Thereafter	 	 	140	 	

	 	
 	 	$	439	 	

	 	

 	Contractual Commitments	

 	Power Supply Agreements with the Distribution Cooperatives	
      During March 2000, Louisiana Generating entered into certain power supply agreements with eleven distribution cooperatives to provide energy, capacity and transmission services. The agreements are standardized into three types, Form A, B, and C. In connection with push down accounting resulting from NRG Energy’s fresh start accounting, certain of the Company’s long-term power supply agreements were determined to be at above or below market rates. As a result, the Company valued these agreements and recognized the fair value of such contracts on the December 6, 2003 balance sheet. The fair value of these contracts that were deemed to be valuable have been included in intangible assets. The fair value of contracts determined to be significantly burdensome were recorded as noncurrent liabilities and will be amortized as an increase to revenues over the terms and conditions of each contract. These contracts consist primarily of the

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long-term power sale agreements the Company has with its cooperative customers and certain others. The gross carrying amount of the unfavorable out of market power sales agreements at both December 31, 2003 and December 6, 2003, was $342.2 million. During the period from December 6, 2003 to December 31, 2003, approximately $1.0 million was amortized as an increase to revenues.

 	Form A Agreements	
      Six of the distribution cooperatives entered into Form A power supply agreements. The Form A agreement is an all-requirements power supply agreement which has an initial term of 25 years, commencing on March 31, 2000. After the initial term, the agreement continues on a year-to-year basis, unless terminated by either party giving five years advance notice.

      Under the Form A power supply agreement, Louisiana Generating is obligated to supply the distribution cooperative all of the energy and capacity required by the distribution cooperative for service to its retail customers although the distribution cooperative has certain limited rights under which it can purchase energy and capacity from third parties.

      The Company must contract for all transmission service required to serve the distribution cooperative and will pass through the costs of transmission service to the cooperative. The Company is required to supply at its cost, without pass through, control area services and ancillary services which transmission providers are not required to provide.

      The Company owns and maintains the substations and other facilities used to deliver energy and capacity to the distribution cooperative and charges the cooperative a monthly specific delivery facility charge for such facilities any additions to, or new delivery facilities. The initial monthly charge is 1% of the value of all of the distribution cooperative’s specific delivery facilities. The cost of additional investment during the term of the agreement will be added to the initial value of the delivery facilities to calculate the monthly specific delivery facility charge.

      Louisiana Generating charges the distribution cooperative a demand charge, a fuel charge and a variable operation and maintenance charge. The demand charge consists of two components, a capital rate and a fixed operation and maintenance rate. The distribution cooperatives have an option to choose one of two fuel options; all nine have selected the first option which is a fixed fee through 2004 and determined using a formula which is based on gas prices and the cost of delivered coal for the period thereafter. At the end of the fifteenth year of the contract, the cooperatives may switch to the second fuel option. The second fuel option consists of a pass-through of fuel costs, with a guaranteed coal heat rate and purchased energy costs, excluding the demand component in purchased power. From time to time, Louisiana Generating may offer fixed fuel rates which the cooperative may elect to utilize. The variable operation and maintenance charge is fixed through 2004 and escalates at either approximately 3% per annum or in accordance with actual changes in specified indices as selected by the distribution cooperative. Five of the distribution cooperatives elected the fixed escalation provision and one elected the specified indices provision.

      The Form A agreement also contains provisions for special rates for certain customers based on the economic development benefits the customer will provide and other rates to improve the distribution cooperative’s ability to compete with service offered by political subdivisions.

 	Form B Agreements	
      One distribution cooperative selected the Form B Power Supply Agreement. The term of the Form B power supply agreement commences on March 31, 2000, and ends on December 31, 2024. The Form B power supply agreement allows the distribution cooperative the right to elect to limit its purchase obligations to “base supply” or also to purchase “supplemental supply.” Base supply is the distribution cooperative’s ratable share of the generating capacity purchased by Louisiana Generating from Cajun Electric. Supplemental supply is

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the cooperative’s requirements in excess of the base supply amount. The distribution cooperative, which selected the Form B agreement, also elected to purchase supplemental supply.

      Louisiana Generating charges the distribution cooperative a monthly specific delivery facility charge of approximately 1.75% of the depreciated net book value of the specific delivery facilities, including additional investment. The distribution cooperative may assume the right to maintain the specific delivery facilities and reduce the charge to 1.25% of the depreciated net book value of the specific delivery facilities. Louisiana Generating also charges the distribution cooperative its ratable share of 1.75% of the depreciated book value of common delivery facilities, which include communications, transmission and metering facilities owned by Louisiana Generating to provide supervisory control and date acquisition, and automatic control for customers.

      For base supply, Louisiana Generating charges the distribution cooperative a demand charge, an energy charge and a fuel charge. The demand charge for each contract year is set forth in the agreement and is subject to increase for environmental legislation or occupational safety and health laws enacted after the effective date of the agreement. Louisiana Generating can increase the demand charge to the extent its cost of providing supplemental supply exceeds $400 per kilowatt (“kW”). The energy charge is fixed through 2004, and decreased slightly for the remainder of the contract term. The fuel charge is a pass-through of fuel and purchased energy costs. The distribution cooperative may elect to be charged based on a guaranteed coal-fired heat rate of 10,600 British Thermal Units per kilowatt-hour (“Btu/kWh”), and it may also select fixed fuel factors as set forth in the agreement for each year through 2008. The one distribution cooperative which selected this form of agreement elected to utilize the fixed fuel factors. For the years after 2008, Louisiana Generating will offer additional fixed fuel factors for five-year periods that may be elected. For the years after 2008, the distribution cooperative may also elect to have its charges computed under the pass-through provisions with or without the guaranteed coal-fired heat rate.

      At the beginning of year six, Louisiana Generating will establish a rate equal to the ratable share of $18 million. The amount of the fund will be approximately $720,000. This fund will be used to offset the energy costs of the Form B distribution cooperatives which elected the fuel pass-through provision of the fuel charge, to the extent the cost of power exceeds $0.04 per kWh. Any funds remaining at the end of the term of the power supply agreement will be returned to Louisiana Generating.

 	Form C Agreements	
      Four distribution cooperatives selected the Form C power supply agreement. The Form C power supply agreement is identical to the Form A power supply agreement, except for the following.

      The term of the Form C power supply agreement was for four years following the closing date of the acquisition of the Cajun facilities. In October 2003, the Louisiana Public Service Commission approved contract extensions for all four Form C distribution cooperatives for terms of an additional five or ten years.

      Louisiana Generating will charge the distribution cooperative a demand rate, a variable operation and maintenance charge and fuel charge. Louisiana Generating will not offer the distribution cooperatives which select the Form C agreement any new incentive rates, but will continue to honor existing incentive rates. At the end of the term of the agreement, the distribution cooperative is obligated to purchase the specific delivery facilities for a purchase price equal to the depreciated book value.

      Louisiana Generating must contract for all transmission services required to serve the distribution cooperative and will pass through the costs of transmission service to the cooperative. Louisiana Generating is required to supply at its cost, without pass-through, control area services and ancillary services which transmission providers are not required to provide.

      Louisiana Generating owns and maintains the substations and other facilities used to deliver energy and capacity to the distribution cooperative and charges the cooperative a monthly specific delivery facility charge

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for such facilities; any additions to, or new delivery facilities. The initial monthly charge is 1% of the value of all of the distribution cooperative’s specific delivery facilities. The cost of additional investment during the term of the agreement will be added to the initial value of the delivery facilities to calculate the monthly specific delivery facility charge.

      Included in the amended and restated Form C agreements is a provision for an annual $250,000 Economic Development Contribution to be shared among the four Form C distribution cooperatives, beginning in April 2004 and extending through the end of the contract terms.

 	Other Power Supply Agreements	
      Louisiana Generating assumed Cajun Electric’s rights and obligations under two consecutive long-term power supply agreements with South Western Electric Power Company (“SWEPCO”), one agreement with South Mississippi Electric Power Association (“SMEPA”) and one agreement with Municipal Energy Agency of Mississippi (“MEAM”).

      The SWEPCO Operating Reserves and Off-Peak Power Sale Agreement, terminates on December 31, 2007. The agreement requires Louisiana Generating to supply 100 megawatts (“MW”) of off-peak energy during certain hours of the day to a maximum of 292,000 megawatt-hours (“MWh”) per year and an additional 100 MW of operating reserve capacity and the associated energy within ten minutes of a phone request during certain hours to a maximum of 43,800 MWh of operating reserve energy per year. The obligation to purchase the 100 MW of off-peak energy is contingent on Louisiana Generating’s ability to deliver operating reserve capacity and energy associated with operating reserve capacity. At Louisiana Generating’s request, it will supply up to 100 MW of nonfirm, on peak capacity and associated energy.

      The SWEPCO Operating Reserves Capacity and Energy Power Sale Agreement is effective January 1, 2008 through December 31, 2026. The agreement requires Louisiana Generating to provide 50 MW of operating reserve capacity within ten minutes of a phone request. In addition, SWEPCO is granted the right to purchase up to 21,900 MWh/year of operating reserve energy.

      The SMEPA Unit Power Sale Agreement is effective through May 31, 2009, unless terminated following certain regulatory changes, changes in fuel costs or destruction of the Cajun facilities. The agreement requires Louisiana Generating to provide 75 MW of capacity and the associated energy from Big Cajun II, Unit 1 and an option for SMEPA to purchase additional capacity and associated energy if Louisiana Generating determines that it is available, in 10 MW increments, up to a total of 200 MW. SMEPA is required to schedule a minimum of 25 MW plus 37% of any additional capacity that is purchased. The capacity charge is fixed through May 31, 2004, and increases for the period form June 1, 2004 to May 31, 2009, including transmission costs to the delivery point and any escalation of expenses. The energy charge is 110% of the incremental fuel cost for Big Cajun II, Unit 1.

      The MEAM Power Sale Agreement is effective through May 31, 2010, with an option for MEAM to extend through September 30, 2015, upon five years advance notice. The agreement requires Louisiana Generating to provide 20 MW of firm capacity and associated energy with an option for MEAM to increase the capacity purchased to a total of 30 MW upon five years advance notice. The capacity charge is fixed. The operation and maintenance charge is a fixed amount which escalates at 3.5% per year. There is a transmission charge which varies depending upon the delivery point. The price for energy associated with the firm capacity is 110% of the incremental generating cost to Louisiana Generating and is adjusted to include transmission losses to the delivery point.

 	Coal Supply Agreement	
      Louisiana Generating has entered into a coal supply agreement with Triton Coal. The coal is primarily sourced from Triton Coal’s Buckskin and North Rochelle mines located in the Powder River Basin, Wyoming.

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The initial term of the coal supply agreement ends on March 31, 2005. The agreement establishes a base price per ton for coal supplied by Triton Coal. The base price is subjected to adjustment for changes in the level of taxes or other government fees and charges, or variations in the caloric value and sulfur content of the coal shipped, and changes in the price of SO2 emission allowances. The base price is based on certain annual weighted average quality specifications, subject to suspension and rejection limits.

 	Coal Transportation Agreement	
      Louisiana Generating entered into a coal transportation agreement with Burlington Northern and Santa Fe Railway and American Commercial Terminal. This agreement provides for the transport of all of the coal requirements of Big Cajun II from the mines in Wyoming to Big Cajun II.

 	Transmission and Interconnection Agreements	
      Louisiana Generating assumed Cajun Electric’s existing transmission agreements with Central Louisiana Electric Company, SWEPCO; and Entergy Services, Inc., acting as agent for Entergy Arkansas, Inc., Entergy Gulf States, Entergy Louisiana, Inc., Entergy Mississippi, Inc., and Entergy New Orleans, Inc. Louisiana Generating also entered into two Interconnection and Operating Agreements with Entergy Gulf States Inc. on May 1, 2002. The Cajun facilities are connected to the transmission system of Entergy Gulf States and power is delivered to the distribution cooperative at various delivery points on the transmission systems of Entergy Gulf States, Entergy Louisiana, Central Louisiana Electric Company and SWEPCO. Louisiana Generating also assumed from Cajun Electric 20 interchange and sales agreements with utilities and cooperatives, providing access to a 12 state area.

 	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 United States. These laws and regulations generally require lengthy and complex processes to obtain licenses, permits and approvals from federal, state and local agencies. If such laws and regulations become more stringent and the Company’s facilities are not exempted from coverage, the Company could be required to make extensive modifications to further reduce potential environmental impacts. Also, the Company could be held responsible under environmental and safety laws for the cleanup of pollutant releases at its facilities or at off-site locations where it has sent wastes.

      The Company and its subsidiaries strive to exceed the standards of compliance with applicable environmental and safety regulations. Nonetheless, the Company expects that future liability under or compliance with environmental and safety requirements could have a material effect on its operations or competitive position. It is not possible at this time to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of possible changes to environmental and safety regulations, regulatory interpretations or enforcement policies. 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.

      The Company establishes accruals where reasonable estimates of probable environmental and safety liabilities are possible. The Company adjusts the accruals when new remediation responsibilities are discovered and probable costs become estimable, or when current remediation estimates are adjusted to reflect new information.

      Under various federal, state and local environmental laws and regulations, a current or previous owner or operator of any facility, including an electric generating 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

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investigation and remediation costs incurred by the party in connection with any releases or threatened releases. These laws, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended by the Superfund Amendments and Reauthorization Act of 1986, impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and courts have interpreted liability under such laws to be strict (without fault) and joint and several. The cost of investigation, remediation or removal of any hazardous or toxic substances or petroleum products could be substantial. The Company has not been named as a potentially responsible party with respect to any off-site waste disposal matter.

      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 the Company (one of the instruments allowed by the Louisiana Department of Environmental Quality for providing financial assurance for expenses associated with closure and post-closure care of the ponds). The value of the trust fund is approximately $4.6 million at December 31, 2002, and the Company is making annual payments to the fund in the amount of about $116,000. See Note 18.

      The Louisiana Department of Environmental Quality has promulgated State Implementation Plan revisions to bring the Baton Rouge ozone nonattainment area into compliance with National Ambient Air Quality Standards. The Company participated in development of the revisions, which require the reduction of NOx emissions at the gas-fired Big Cajun I Power Station and coal-fired Big Cajun II Power Station to 0.1 pounds NOx per million Btu heat input and 0.21 pounds NOx per million Btu heat input, respectively. This revision of the Louisiana air rules would appear to constitute a change-in-law covered by agreement between Louisiana Generating LLC and the electric cooperatives allowing the costs of added combustion controls to be passed through to the cooperatives. The capital cost of combustion controls required at the Big Cajun II Generating Station to meet the State’s NOx regulations will total about $10.0 million each for Units 1 & 2. Unit 3 has already made such changes. The capital cost of combustion controls required at the Big Cajun I Generating Station to meet the State’s NOx regulations will total about $5 million to $10 million for the Unit 1 & 2 steam boilers.

 	Legal Issues	

 	United States Environmental Protection Agency Request for Information under Section 114 of the Clean Air Act	
      On January 27, 2004, Louisiana Generating, LLC and Big Cajun II received a request for information under Section 114 of the Clean Air Act from the United States Environmental Protection Agency (“EPA”) seeking information primarily relating to physical changes made at Big Cajun II in 1994 and 1995 by the predecessor owner of that facility. Louisiana Generating, LLC and Big Cajun II have been responding to the EPA request in an appropriate manner. At the present time, the Company cannot predict the probable outcome in this matter.

      Two lawsuits are pending in Federal Court involving 39 former employees of Cajun Electric Power Cooperative, Inc. who claim age/race/sex discrimination in failure to hire by Louisiana Generating. One lawsuit was dismissed on summary judgment and has been appealed. In the remaining lawsuit, we are awaiting the District Court’s ruling on Louisiana Generating’s motions for summary judgment.

 	In the Matter of Louisiana Generating, LLC, Adversary Proceeding No. 2002-1095 1-EQ on the Docket of the Louisiana Division of Administrative Law	
      During 2000, the Louisiana Department of Environmental Quality (“DEQ”) issued a Part 70 Air Permit modification to Louisiana Generating to construct and operate two 120 MW natural gas-fired turbines. The Part 70 Air Permit set emissions limits for the criteria air pollutants, including NOx, based on the application

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of Best Available Control Technology (“BACT”). The BACT limitation for NOx was based on the guarantees of the manufacturer, Siemens-Westinghouse. Louisiana Generating sought an interim emissions limit to allow Siemens-Westinghouse time to install additional control equipment. To establish the interim limit, DEQ issued a Compliance Order and Notice of Potential Penalty, No. AE-CN-02-0022, on September 8, 2002, which is, in part, subject to the referenced administrative hearing. DEQ alleged that Louisiana Generating did not meet its NOx emissions limit on certain days, did not conduct all opacity monitoring and did not complete all record keeping and certification requirements. Louisiana Generating intends to vigorously defend certain claims and any future penalty assessment, while also seeking an amendment of its limit for NO(x). An amended permit application and an amended BACT analysis were submitted to DEQ on February 27, 2004. DEQ is presently reviewing the amended application. In addition, NRG Energy may assert breach of warranty claims against the manufacturer. With respect to the administrative action described above, at this time the Company is unable to predict the eventual outcome of this matter or the potential loss contingencies, if any, to which the Company may be subject.

16.	Regulatory Issues	
      The Company’s assets are located within the control areas of the local, regulated, and sometimes vertically integrated, utilities, primarily Entergy Corporation (“Entergy”). The utility performs the scheduling, reserve and reliability functions that are administered by the Independent System Operators (“ISO”) in certain other regions of the United States and Canada. The Company operates a National Electric Reliability Council (“NERC”) certified control areas within the Entergy control area, which is comprised of the Company’s generating assets and its co-op customer loads. Although the reliability functions performed are essentially the same, the primary differences between these markets lie principally in the physical delivery and price discovery mechanisms. In the South Central region, all power sales and purchases are consummated bilaterally between individual counter-parties, and physically delivered either within or across the physical control areas of the transmission owners from the source generator to the sink load. Transacting counter-parties are required to reserve and purchase transmission services from the intervening transmission owners at their Federal Energy Regulatory Commission (“FERC”) approved tariff rates. Included with these transmission services are the reserve and ancillary costs. Energy prices in the South Central region are determining and agreed to in bilateral negotiations between representatives of the transacting counter-parties, using market information gleaned by the individual marketing agents arranging the transactions.

      In the South Central area, including Entergy’s service territory, the present energy market is not a centralized market and does not have an independent system operator as is found in the Northeast markets. The Company presently has long-term all requirements contracts with 11 Louisiana Distribution Cooperatives, and long-term contracts with the Municipal Energy Agency of Mississippi, South Mississippi Electric Power Association and Southwestern Electric Power Company. The Distribution Cooperatives serve approximately 300,000 to 350,000 retail customers.

      On March 31, 2004, Entergy filed with FERC a proposal: to have an independent person monitor the Entergy operation of the transmission system, to review the pricing structure for transmission expansion and to establish a weekly procurement process by which Entergy and other load serving entities could purchase energy. On June 30, 2004, the Company intervened in the case and requested FERC reject the proposals. FERC has not ruled on this request. Also, it is unclear at this time how these recent developments will impact the Company.

17.	Jointly Owned Plant	
      On March 31, 2000, Louisiana Generating acquired a 58% interest in the Big Cajun II, Unit 3 generation plant. Entergy Gulf States owns the remaining 42%. Big Cajun II, Unit 3 is operated and maintained by Louisiana Generating pursuant to a joint ownership participation and operating agreement. Under this

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agreement, Louisiana Generating and Entergy Gulf States are each entitled to their ownership percentage of the hourly net electrical output of Big Cajun II, Unit 3. All fixed costs are shared in proportion to the ownership interests. Fixed costs include the cost of operating common facilities. All variable costs are borne in proportion to the energy delivered to the owners. The Company’s statements of operations include its share of all fixed and variable costs of operating the unit.

      The Company’s 58% share of the property, plant and equipment and construction in progress as revalued to fair value upon the application of push down accounting at December 31, 2003 and December 6, 2003, was $183.2 million and $183.2 million, respectively, and corresponding accumulated depreciation and amortization was $0.5 million and $0, respectively. The Company’s 58% share of the original cost is included in property, plant and equipment and construction in progress at December 31, 2002, was $189.0 million and corresponding accumulated depreciation and amortization was $12.3 million.

18.	Decommissioning Fund	
      The Company is required by the State of Louisiana Department of Environmental Quality (“DEQ”) to rehabilitate its Big Cajun II ash and wastewater impoundment areas upon removal from service of the Big Cajun II facilities. On July 1, 1989, a guarantor trust fund (the “Solid Waste Disposal Trust Fund”) was established to accumulate the estimated funds necessary for such purpose. The Company’s predecessor deposited $1.06 million in the Solid Waste Disposal Trust Fund in 1989, and funded $116,000 annually thereafter, based upon an estimated future rehabilitation cost (in 1989 dollars) of approximately $3.5 million and the remaining estimated useful life of the Big Cajun II facilities. Cumulative contributions to the Solid Waste Disposal Trust Fund and earnings on the investments therein are accrued as a decommissioning liability. At December 31, 2003, December 6, 2003 and December 31, 2002, the carrying value of the trust fund investments and the related accrued decommissioning liability was approximately $4.8 million, 4.8 million, and $4.6 million, respectively. The trust fund investments are comprised of various debt securities of the United States and are carried at amortized cost, which approximates their fair value.

19.	Sale of Equity Method Investment	
      In September 2002, NRG Energy agreed to sell its indirect 50% interest in SRW Cogeneration LP (“SRW”), to its partner in SRW Conoco, Inc. in consideration for Conoco’s agreement to terminate or assume all of the obligations of NRG Energy in relation to SRW. SRW owns a cogeneration facility in Orange County, Texas. The Company recorded a charge of approximately $48 million during the third quarter to write down the carrying value of its investment due to the pending sale. The sale closed on November 5, 2002.

20.	Guarantees	
      In November 2002, the FASB issued FIN No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others . The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor’s fiscal year end. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002. The interpretation addresses the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees. The interpretation also clarifies the requirements related to the recognition of a liability by a guarantor at the inception of the guarantee for the obligations the guarantor has undertaken in issuing the guarantee.

      In connection with push down accounting, all outstanding guarantees were considered new; accordingly, the Company applied the provisions of FIN 45 to all of those guarantees. Each guarantee was reviewed for the requirement to recognize a liability at inception.

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      The Company was a guarantor of the bonds issued on March 30, 2000, to acquire the Cajun facilities. On December 23, 2003, South Central paid in full the remaining balance of such bonds.

      The Company guarantees the purchase and sale of fuel, emission credits and power generation to and from third parties in connection with the operation of some of the Company’s generation facilities. At December 31, 2003 and December 6, 2003, the Company’s obligations pursuant to its guarantees of the performance of its subsidiaries totaled approximately $13 million and $13 million, respectively. As of December 31, 2002, the Company’s obligations pursuant to its guarantees of the performance of its subsidiaries totaled approximately $39.7 million. In addition, the Company had one guarantee related to the purchase of transmission service that has an indeterminate value at December 31, 2003, December 6, 2003 and December 31, 2002.

      In June 2002, NRG Peaker Finance Company LLC issued $325 million of secured bonds to make loans to affiliates which own natural gas fired “peaker” electric generating projects. At December 31, 2003 and December 6, 2003, $239.3 million and $246.7 million remain outstanding, respectively. NRG Peaker Finance Company LLC advanced unsecured loans in the amount of $107.4 million to Bayou Cove through project loan agreements. The remaining $217.6 million was advanced to NRG Rockford LLC and Rockford II LLC, indirect wholly owned subsidiaries of NRG Energy. At December 31, 2003 and December 6, 2003, Bayou Cove had an intercompany loan outstanding in the amount of $81.7 million and $105.5 million, respectively. The principal and interest payments, in addition to the obligation to pay fees and other finance expenses, in connection with the bonds are jointly and severally guaranteed by each of the three projects. As a result, NRG South Central’s obligation pursuant to its guarantee of the secured bonds is $239.3 million at December 31, 2003.

      On December 23, 2003, the Company’s ultimate parent, NRG Energy, issued $1.25 billion of 8% Second Priority Notes, due and payable on December 15, 2013. On January 28, 2004, NRG Energy also issued $475.0 million of Second Priority Notes, under the same terms and indenture as its December 23, 2003 offering.

      NRG Energy’s payment obligations under the notes and all related parity lien obligations are guaranteed on an unconditional basis by each of NRG Energy’s current and future restricted subsidiaries, of which the Company is one. The notes are jointly and severally guaranteed by each of the guarantors. The subsidiary guarantees of the notes are secured, on a second priority basis, equally and ratably with any future parity lien debt, by security interest in all of the assets of the guarantors, except certain excluded assets, subject to liens securing parity lien debt and other permitted prior liens.

      The Company’s obligations pursuant to its guarantees of the performance, equity and indebtedness obligations were as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantee/	 	 	 	 	 	 	
 	 	Maximum	 	 	 	Expiration	 	 	
 	 	Exposure	 	Nature of Guarantee	 	Date	 	Triggering Event	

	 	

	 	

	 	

	
 	 	(In thousands	 	 	 	 	 	 	
 	 	of dollars)	 	 	 	 	 	 	
Project/Subsidiary	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
NRG Energy Second Priority Notes due 2013	 	$	1,753,000	 	 	Obligations under credit agreement	 	 	2013	 	 	 	Nonperformance	 	

21.	Income Taxes (Restatement)	
      The Company is included in the consolidated tax return filings as a wholly owned indirect subsidiary of NRG Energy. Reflected in the financial statements and notes below are separate company federal and state tax provisions as if the Company had prepared separate filings. An income tax provision has been established

37

 
NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

on the accompanying consolidated financial statements as of the earliest period presented in order to reflect income taxes as if the Company filed its own tax return. The Company’s ultimate parent, NRG Energy, does not have a tax allocation agreement with its subsidiaries and prior to January 1, 2003, income taxes were not recorded or allocated to non tax paying entities or entities such as the Company which are treated as disregarded entities for tax purposes. Accordingly, the previously issued consolidated financial statements for the years ended December 31, 2002 and 2001, have been restated to include the effects of recording an income tax provision. Because the Company is not a party to a tax sharing agreement, current tax expense (benefit) is recorded as a capital contribution from (distribution to) the Company’s parent. The cumulative effect of recording an income tax provision (benefit) and deferred taxes resulted in recording as of December 31, 2000, a net deferred tax liability of $35.7 million and a reduction to members’ equity of $35.7 million.

      The provision (benefit) for income taxes consists of the following:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Current	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Federal	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	
 	State	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Deferred	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Federal	 	 	161	 	 	 	—	 	 	 	(31,871	)	 	 	3,278	 	
 	State	 	 	40	 	 	 	—	 	 	 	(7,918	)	 	 	815	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	201	 	 	 	—	 	 	 	(39,789	)	 	 	4,093	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Total income tax expense (benefit)	 	$	201	 	 	$	—	 	 	$	(39,789	)	 	$	4,093	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Effective tax rate	 	 	40.7	%	 	 	0.0	%	 	 	23.2	%	 	 	40.5	%	
      The pre-tax income (loss) was as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
U.S. 	 	$	494	 	 	$	(27,969	)	 	$	(171,874	)	 	$	10,108	 	
38

 
NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The components of the net deferred income tax liability were:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Deferred tax liabilities	 	 	 	 	 	 	 	 	 	 	 	 	
 	Property	 	$	—	 	 	$	—	 	 	$	11,205	 	
 	Discount/premium on notes	 	 	9,648	 	 	 	9,648	 	 	 	—	 	
 	Emissions credits	 	 	37,866	 	 	 	37,866	 	 	 	—	 	
 	Other	 	 	129	 	 	 	93	 	 	 	5,449	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total deferred tax liabilities	 	 	47,643	 	 	 	47,607	 	 	 	16,654	 	
Deferred tax assets	 	 	 	 	 	 	 	 	 	 	 	 	
 	Deferred compensation, accrued vacation and other reserves	 	 	3,371	 	 	 	3,357	 	 	 	916	 	
 	Difference between book and tax basis of contracts	 	 	129,960	 	 	 	130,360	 	 	 	—	 	
 	Property	 	 	51,744	 	 	 	53,485	 	 	 	—	 	
 	Domestic tax loss carryforwards	 	 	91,364	 	 	 	89,429	 	 	 	50,938	 	
 	Other	 	 	8,768	 	 	 	8,741	 	 	 	499	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total deferred tax assets (before valuation allowance)	 	 	285,207	 	 	 	285,372	 	 	 	52,353	 	
Valuation allowance	 	 	(237,564	)	 	 	(237,765	)	 	 	(35,699	)	

	 	 	 	

	 	 	 	

	 	
Net deferred tax assets	 	 	47,643	 	 	 	47,607	 	 	 	16,654	 	

	 	 	 	

	 	 	 	

	 	
Net deferred tax liability	 	$	—	 	 	$	—	 	 	$	—	 	

	 	 	 	

	 	 	 	

	 	
      The net deferred tax liability consists of:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Current deferred tax liability (asset)	 	$	7,348	 	 	$	7,292	 	 	$	(85	)	
Less current valuation allowance	 	 	(7,348	)	 	 	(7,292	)	 	 	85	 	

	 	 	 	

	 	 	 	

	 	
Net current deferred tax liability (asset)	 	 	—	 	 	 	—	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
Noncurrent deferred tax (asset)	 	 	(244,912	)	 	 	(245,058	)	 	 	(35,614	)	
Less noncurrent valuation allowance	 	 	244,912	 	 	 	245,058	 	 	 	35,614	 	

	 	 	 	

	 	 	 	

	 	
Net noncurrent deferred tax liability (asset)	 	 	—	 	 	 	—	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
Net deferred tax liability	 	$	—	 	 	$	—	 	 	$	—	 	

	 	 	 	

	 	 	 	

	 	
39

 
NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The effective income tax rates of continuing operations differ from the statutory federal income tax rate of 35% as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	 	 	 	 	
 	 	Company	 	 	 	Predecessor Company	 	 	

	 	 	 	

	 	 	
 	 	For the	 	 	 	For the	 	 	 	 	
 	 	Period from	 	 	 	Period from	 	 	 	 	 	 	
 	 	December 6,	 	 	 	January 1,	 	 	 	For the Years Ended	 	 	
 	 	2003 to	 	 	 	2003 to	 	 	 	December 31,	 	 	
 	 	December 31,	 	 	 	December 5,	 	 	 	

	 	 	
 	 	2003	 	 	 	2003	 	 	 	2002	 	 	 	2001	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	
 	 	 	
 	 	(In thousands of dollars)	
Income (loss) before taxes	 	$	494	 	 	 	 	 	 	$	(27,969	)	 	 	 	 	 	$	(171,874	)	 	 	 	 	 	$	10,108	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	
Tax at 35%	 	 	173	 	 	 	35.0	%	 	 	(9,789	)	 	 	35.0	%	 	 	(60,156	)	 	 	35.0	%	 	 	3,538	 	 	 	35.0	%	
State taxes (net of federal benefit)	 	 	26	 	 	 	5.3	%	 	 	(1,455	)	 	 	5.2	%	 	 	(5,147	)	 	 	3.0	%	 	 	529	 	 	 	5.2	%	
Valuation allowance	 	 	—	 	 	 	0.0	%	 	 	11,244	 	 	 	(40.2	)%	 	 	35,699	 	 	 	(20.8	)%	 	 	—	 	 	 	0.0	%	
Other	 	 	2	 	 	 	0.4	%	 	 	—	 	 	 	—	%	 	 	(10,185	)	 	 	5.9	%	 	 	26	 	 	 	0.3	%	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	
Income tax expense (benefit)	 	$	201	 	 	 	40.7	%	 	$	—	 	 	 	0.0	%	 	$	(39,789	)	 	 	23.1	%	 	$	4,093	 	 	 	40.5	%	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	

22.	Reorganization Cash Payments and Receipts	

 	Cash Receipts	
      During the period from May 14, 2003 to December 5, 2003, the Company received $0.8 million of interest income on cash balances. No such amounts were received during the period from December 6, 2003 to December 31, 2003.

 	Cash Payments	

 	Professional Fees	
      During the period from May 14, 2003 to December 5, 2003 and the period from December 6, 2003 to December 31, 2003, the Company made cash payments for employment separation costs and professional fees to financial and legal advisors of $11.5 million and $0.1 million, respectively.

 	Refinancing Activities	
      The Company made cash payments of $750.8 million related to the repayment of debt, including accrued interest of $15.3 million upon the emergence from bankruptcy on December 23, 2003, with proceeds from NRG Energy’s recently completed corporate level refinancing. The Company also made cash payments of $11.3 million for a pre-payment settlement upon the early payment of the debt.

 	Creditor Payments	
      Upon the Company’s emergence from bankruptcy, no cash payments were made to creditors during the period from December 6, 2003 to December 31, 2003.

40

 

REPORT OF INDEPENDENT AUDITORS
ON FINANCIAL STATEMENT SCHEDULE

To the Members of
NRG South Central Generating LLC:

      Our audits of the consolidated financial statements referred to in our report dated March 10, 2004, also included an audit of the financial statement schedule listed herein. In our opinion, this financial statement schedule for the period from January 1, 2003 to December 5, 2003 and for the two years ended December 31, 2002, presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
 	 	
 	/s/ PRICEWATERHOUSECOOPERS LLP	

	
 	PricewaterhouseCoopers LLP	
Minneapolis, Minnesota
March 10, 2004

41

 

REPORT OF INDEPENDENT AUDITORS
ON FINANCIAL STATEMENT SCHEDULE

To the Members of
NRG South Central Generating LLC:

      Our audits of the consolidated financial statements referred to in our report dated March 10, 2004, also included an audit of the financial statement schedule listed herein. In our opinion, this financial statement schedule for the period from December 6, 2003 to December 31, 2003 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
 	 	
 	/s/ PRICEWATERHOUSECOOPERS LLP	

	
 	PricewaterhouseCoopers LLP	
Minneapolis, Minnesota
March 10, 2004

42

 

NRG SOUTH CENTRAL GENERATING LLC

SCHEDULE II. VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2003, 2002 and 2001

 	 	 	 	Additions	 	 	 	 	

	 	 	 	 	
 	 	Balance at	 	Charged to	 	 	 	 	 	Balance at	
 	 	Beginning of	 	Costs and	 	Charged to	 	 	 	End of	
Description	 	Period	 	Expenses	 	Other	 	Deductions	 	Period	

	 	

	 	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands)	
Income tax valuation allowance, deducted from deferred tax assets in the balance sheet:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Predecessor Company	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Year ended December 31, 2001	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	
Year ended December 31, 2002	 	 	—	 	 	 	35,699	 	 	 	—	 	 	 	—	 	 	 	35,699	 	
January 1 - December 5, 2003	 	 	35,699	 	 	 	202,066	 	 	 	—	 	 	 	—	 	 	 	237,765	 	

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reorganized Company	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
December 6 - December 31, 2003	 	 	237,765	 	 	 	—	 	 	 	—	 	 	 	(201	)	 	 	237,564	 	
43

 

EXHIBIT 99.7

NRG EASTERN LLC

FINANCIAL STATEMENTS

At December 31, 2003, December 6, 2003 and
December 31, 2002, and for the Period from
December 6, 2003 to December 31, 2003, the Period
from January 1, 2003 to December 5, 2003 and for
the Years Ended December 31, 2002 and 2001

44

 

NRG EASTERN LLC

INDEX
 	 	 	 	 	
 	 	Page(s)	

	
Reports of Independent Auditors	 	 	2-3	 	
 	
Financial Statements	 	 	 	 	
Balance Sheets at December 31, 2003, December 6, 2003 and December 31, 2002	 	 	4	 	
Statements of Operations for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001	 	 	5	 	
Statements of Member’s Equity for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001	 	 	6	 	
Statements of Cash Flows for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001	 	 	7	 	
Notes to Financial Statements	 	 	8-17	 	
1

 

REPORT OF INDEPENDENT AUDITORS

To the Member of
NRG Eastern LLC

      In our opinion, the accompanying balance sheet and the related statements of operations, of member’s equity, and of cash flows present fairly, in all material respects, the financial position of NRG Eastern LLC (“Predecessor Company”) at December 31, 2002, and the results of their operations and their cash flows for the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      As discussed in Note 1 to the financial statements, on May 14, 2003, NRG Energy, Inc. and certain of its subsidiaries including the Company, filed a petition with the United States Bankruptcy Court for the Southern District of New York for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. NRG Energy, Inc.’s Plan of Reorganization was substantially consummated on December 5, 2003, and Reorganized NRG emerged from bankruptcy. The Company emerged from bankruptcy on December 23, 2003, pursuant to a separate plan of reorganization referred to as the Northeast/ South Central Plan of Reorganization. The impact of NRG Energy, Inc.’s emergence from bankruptcy and fresh start accounting was applied to the Company on December 5, 2003 under push down accounting methodology.
 	 	
 	/s/ PRICEWATERHOUSECOOPERS LLP	

	
 	PricewaterhouseCoopers LLP	
Minneapolis, Minnesota
March 10, 2004

2

 

REPORT OF INDEPENDENT AUDITORS

To the Member of
NRG Eastern LLC

      In our opinion, the accompanying balance sheets and the related statements of operations, of members’ equity, and of cash flows present fairly, in all material respects, the financial position of NRG Eastern LLC (“Reorganized Company”) at December 31, 2003 and December 6, 2003, and the results of their operations and their cash flows for the period from December 6, 2003 to December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      As discussed in Note 1 to the financial statements, on May 14, 2003, NRG Energy, Inc. and certain of its subsidiaries including the Company, filed a petition with the United States Bankruptcy Court for the Southern District of New York for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. NRG Energy, Inc.’s Plan of Reorganization was substantially consummated on December 5, 2003, and Reorganized NRG emerged from bankruptcy. The Company emerged from bankruptcy on December 23, 2003, pursuant to a separate plan of reorganization referred to as the Northeast/ South Central Plan of Reorganization. The impact of NRG Energy, Inc.’s emergence from bankruptcy and fresh start accounting was applied to the Company on December 5, 2003 under push down accounting methodology.
 	 	
 	/s/ PRICEWATERHOUSECOOPERS LLP	

	
 	PricewaterhouseCoopers LLP	
Minneapolis, Minnesota
March 10, 2004

3

 

NRG EASTERN LLC

BALANCE SHEETS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
ASSETS	
Investment in affiliate	 	$	567,740	 	 	$	279,612	 	 	$	489,783	 	
Noncurrent deferred income tax	 	 	45,556	 	 	 	45,716	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total assets	 	$	613,296	 	 	$	325,328	 	 	$	489,783	 	

	 	 	 	

	 	 	 	

	 	
 	
LIABILITIES AND MEMBER’S EQUITY	
Current liabilities	 	 	 	 	 	 	 	 	 	 	 	 	
 	Accounts payable — affiliates	 	$	—	 	 	$	—	 	 	$	398	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total current liabilities	 	 	—	 	 	 	—	 	 	 	398	 	
Noncurrent deferred income tax	 	 	—	 	 	 	—	 	 	 	29,198	 	
Commitments and contingencies	 	 	 	 	 	 	 	 	 	 	 	 	
Member’s equity	 	 	613,296	 	 	 	325,328	 	 	 	460,187	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total liabilities and member’s equity	 	$	613,296	 	 	$	325,328	 	 	$	489,783	 	

	 	 	 	

	 	 	 	

	 	
The accompanying notes are an integral part of these financial statements.

4

 

NRG EASTERN LLC

STATEMENTS OF OPERATIONS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
General and administrative expenses	 	$	—	 	 	$	—	 	 	$	159	 	 	$	98	 	
Equity earnings (losses) in unconsolidated affiliate	 	 	5,153	 	 	 	(127,756	)	 	 	1,943	 	 	 	105,628	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	Income (loss) before income taxes	 	 	5,153	 	 	 	(127,756	)	 	 	1,784	 	 	 	105,530	 	
Income tax expense (benefit)	 	 	2,230	 	 	 	(54,912	)	 	 	1,662	 	 	 	45,684	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	Net income (loss)	 	$	2,923	 	 	$	(72,844	)	 	$	122	 	 	$	59,846	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
The accompanying notes are an integral part of these financial statements.

5

 

NRG EASTERN LLC

STATEMENTS OF MEMBER’S EQUITY
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	Accumulated	 	 	
 	 	Member	 	Member	 	Accumulated	 	Other	 	Total	

	 	Contributions/	 	Net Income	 	Comprehensive	 	Member’s	
 	 	Units	 	Amount	 	Distributions	 	(Loss)	 	Income	 	Equity	

	 	

	 	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Balances at December 31, 2000
(Predecessor Company)	 	 	1,000	 	 	$	1	 	 	$	361,878	 	 	$	—	 	 	$	—	 	 	$	361,879	 	
Cumulative effect upon adoption of SFAS No. 133	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	7,050	 	 	 	7,050	 	
Impact of SFAS No. 133 for the year ending December 31, 2001	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	46,821	 	 	 	46,821	 	
Net income	 	 	 	 	 	 	 	 	 	 	—	 	 	 	59,846	 	 	 	—	 	 	 	59,846	 	

	 	
Comprehensive income	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	113,717	 	
Contribution from member	 	 	—	 	 	 	—	 	 	 	41,889	 	 	 	—	 	 	 	—	 	 	 	41,889	 	
Distribution to member	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(26,364	)	 	 	—	 	 	 	(26,364	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Balances at December 31, 2001
(Predecessor Company)	 	 	1,000	 	 	 	1	 	 	 	403,767	 	 	 	33,482	 	 	 	53,871	 	 	 	491,121	 	
Impact of SFAS No. 133 for the year ending December 31, 2002	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(39,453	)	 	 	(39,453	)	
Net income	 	 	—	 	 	 	—	 	 	 	—	 	 	 	122	 	 	 	—	 	 	 	122	 	

	 	
Comprehensive loss	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(39,331	)	
Contribution from member	 	 	—	 	 	 	—	 	 	 	8,397	 	 	 	—	 	 	 	—	 	 	 	8,397	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Balances at December 31, 2002
(Predecessor Company)	 	 	1,000	 	 	 	1	 	 	 	412,164	 	 	 	33,604	 	 	 	14,418	 	 	 	460,187	 	
Impact of SFAS No. 133 for the period ending December 5, 2003	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(14,418	)	 	 	(14,418	)	
Net loss	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(72,844	)	 	 	—	 	 	 	(72,844	)	

	 	
Comprehensive loss	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(87,262	)	
Distribution to member	 	 	—	 	 	 	—	 	 	 	(45,495	)	 	 	—	 	 	 	—	 	 	 	(45,495	)	
Contribution from member	 	 	—	 	 	 	—	 	 	 	7,973	 	 	 	—	 	 	 	—	 	 	 	7,973	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Balances at December 5, 2003
(Predecessor Company)	 	 	1,000	 	 	 	1	 	 	 	374,642	 	 	 	(39,240	)	 	 	—	 	 	 	335,403	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Pushdown accounting adjustments	 	 	—	 	 	 	—	 	 	 	(49,315	)	 	 	39,240	 	 	 	—	 	 	 	(10,075	)	
Balances at December 6, 2003
(Reorganized Company)	 	 	1,000	 	 	 	1	 	 	 	325,327	 	 	 	—	 	 	 	—	 	 	 	325,328	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Contribution from member	 	 	—	 	 	 	—	 	 	 	285,045	 	 	 	—	 	 	 	—	 	 	 	285,045	 	
Net income	 	 	—	 	 	 	—	 	 	 	—	 	 	 	2,923	 	 	 	—	 	 	 	2,923	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Balances at December 31, 2003
(Reorganized Company)	 	 	1,000	 	 	$	1	 	 	$	610,372	 	 	$	2,923	 	 	$	—	 	 	$	613,296	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
The accompanying notes are an integral part of these financial statements.

6

 

NRG EASTERN LLC

STATEMENTS OF CASH FLOWS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Cash flows from operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	$	2,923	 	 	$	(72,844	)	 	$	122	 	 	$	59,846	 	
Adjustments to reconcile net income (loss) to net cash provided by operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Distributions (less than) in excess of equity earnings/losses of unconsolidated affiliates	 	 	(5,153	)	 	 	127,756	 	 	 	(1,943	)	 	 	(79,264	)	
 	Deferred income tax	 	 	160	 	 	 	(62,885	)	 	 	(6,735	)	 	 	3,795	 	
 	Current tax expense — noncash contribution from member	 	 	2,070	 	 	 	7,973	 	 	 	8,397	 	 	 	41,889	 	
 	Changes to assets and liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Accounts payable — affiliates	 	 	—	 	 	 	(398	)	 	 	159	 	 	 	98	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	Net cash (used in) provided by operating activities	 	 	—	 	 	 	(398	)	 	 	—	 	 	 	26,364	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Cash flows from investing activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Investment in affiliates	 	 	(282,975	)	 	 	—	 	 	 	—	 	 	 	—	 	
Dividends received from investment	 	 	—	 	 	 	45,893	 	 	 	—	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	Net cash (used in) provided by investing activities	 	 	(282,975	)	 	 	45,893	 	 	 	—	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Cash flows from financing activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Distribution to member	 	 	—	 	 	 	(45,495	)	 	 	—	 	 	 	(26,364	)	
Contribution from member	 	 	282,975	 	 	 	—	 	 	 	—	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	Net cash provided by (used in) financing activities	 	 	282,975	 	 	 	(45,495	)	 	 	—	 	 	 	(26,364	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	Net change in cash and cash equivalents	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Cash and cash equivalents	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Beginning of period	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
End of period	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Supplemental disclosures of cash flow information	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Noncash contribution from member for current tax expense	 	$	2,070	 	 	$	7,973	 	 	$	8,397	 	 	$	41,889	 	
The accompanying notes are an integral part of these financial statements.

7

 

NRG EASTERN LLC

NOTES TO FINANCIAL STATEMENTS

1.     Organization

      NRG Eastern LLC (the “Company”), a directly held wholly owned subsidiary of NRG Energy, Inc. (“NRG Energy”), primarily holds a 50% equity interest of NRG Northeast Generating LLC (“Northeast Gen”) which owns electric power generation plants in the northeastern region of the United States. Northeast Gen was formed in 1999 for the purpose of financing, acquiring, owning, operating and maintaining, through its subsidiaries and affiliates the facilities owned by Arthur Kill Power LLC, Astoria Gas Turbine Power LLC, Connecticut Jet Power LLC, Devon Power LLC, Dunkirk Power LLC, Huntley Power LLC, Middletown Power LLC, Montville Power LLC, Norwalk Power LLC, Oswego Harbor Power LLC and Somerset Power LLC.

 	Recent Developments	
      On May 14, 2003, NRG Energy and 25 of its direct and indirect wholly owned subsidiaries commenced voluntary petitions under Chapter 11 of the Bankruptcy Code in the United Sates Bankruptcy Court for the Southern District of New York. Northeast Gen was included in the Chapter 11 filing. During the bankruptcy proceedings, NRG Energy continued to conduct business and manage the companies as debtors in possession pursuant to sections 1107(a) and 1108 of the bankruptcy code. Two plans of reorganization were filed in connection with the restructuring efforts. The first, filed on May 14, 2003, and referred to as NRG Energy’s Plan of Reorganization, relates to NRG Energy and the other NRG Energy plan debtors. The second plan, relating to the Company, Northeast Gen and, its subsidiaries and the South Central subsidiaries, referred to as the Northeast/ South Central Plan of Reorganization, was filed on September 17, 2003. On November 24, 2003, the bankruptcy court entered an order confirming NRG Energy’s Plan of Reorganization and the plan became effective on December 5, 2003. On November 25, 2003, the bankruptcy court issued an order confirming the Northeast/ South Central Plan of Reorganization and the plan became effective on December 23, 2003. In connection with NRG Energy’s emergence from bankruptcy, NRG Energy adopted fresh start reporting in accordance with AICPA Statement of Position 90-7,  Financial Reporting by Entities in Reorganization Under the Bankruptcy Code  (“SOP 90-7”) on December 5, 2003. NRG Energy’s fresh start reporting was applied to the Company on a push down accounting basis with the financial statements impact recorded as an adjustment to the December 6, 2003, member’s equity in the amount of $10.1 million.

 	NRG Energy’s Plan of Reorganization	
      NRG Energy’s Plan of Reorganization is the result of several months of intense negotiations among NRG Energy, Xcel Energy, Inc. (“Xcel Energy”) and the two principal committees representing NRG Energy creditor groups, referred to as the Global Steering Committee and the Noteholder Committee. A principal component of NRG Energy’s Plan of Reorganization is a settlement with Xcel Energy in which Xcel Energy agreed to make a contribution consisting of cash (and, under certain circumstances, its stock) in the aggregate amount of up to $640 million to be paid in three separate installments following the effective date of NRG Energy’s Plan of Reorganization. The Xcel Energy settlement agreement resolves any and all claims existing between Xcel Energy and NRG Energy and/or its creditors and, in exchange for the Xcel Energy contribution, Xcel Energy is receiving a complete release of claims from NRG Energy and its creditors, except for a limited number of creditors who have preserved their claims as set forth in the confirmation order entered on November 24, 2003.

 	Northeast/ South Central Plan of Reorganization	
      The Northeast/ South Central Plan of Reorganization was proposed on September 17, 2003, after the necessary financing commitments were secured. On November 25, 2003, the bankruptcy court issued an order confirming the Northeast/ South Central Plan of Reorganization and the plan became effective on December 23, 2003. In connection with the order confirming the Northeast/ South Central Plan of Reorganization, the court entered a separate order which provides that the allowed amount of the bondholders’ claims shall

8

 
NRG EASTERN LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

equal in the aggregate the sum of (i) $1.3 billion plus (ii) any accrued and unpaid interest at the applicable contract rates through the date of payment to the indenture trustee plus (iii) the reasonable fees, costs or expenses of the collateral agent and indenture trustee (other than reasonable professional fees incurred from October 1, 2003) plus (iv) $19.6 million, ratably, for each holder of bonds based upon the current outstanding principal amount of the bonds and irrespective of (a) the date of maturity of the bonds, (b) the interest rate applicable to such bonds and (c) the issuer of the bonds. The settlement further provides that the Northeast/ South Central debtors shall reimburse the informal committee of secured bondholders, the indenture trustee, the collateral agent, and two additional bondholder groups, for any reasonable professional fees, costs or expenses incurred from October 1, 2003 to January 31, 2004, up to a maximum amount of $2.5 million (including in such amount any post-October 1, 2003, fees already reimbursed), with the exception that the parties to the settlement reserved their respective rights with respect to any additional reasonable fees, costs or expenses incurred subsequent to November 25, 2003, related to matters not reasonably contemplated by the implementation of the settlement of the Northeast/ South Central Plan of Reorganization.

      The creditors of Northeast Gen and South Central subsidiaries were unimpaired by the Northeast/ South Central Plan of Reorganization. The creditors holding allowed general secured claims were paid in cash, in full on the effective date of the Northeast/ South Central Plan of Reorganization. Holders of allowed unsecured claims will receive or have received either (i) cash equal to the unpaid portion of their allowed unsecured claim, (ii) treatment that leaves unaltered the legal, equitable and contractual rights to which such unsecured claim entitles the holder of such claim, (iii) treatment that otherwise renders such unsecured claim unimpaired pursuant to section 1124 of the bankruptcy code or (iv) such other, less favorable treatment that is confirmed in writing as being acceptable to such holder and to the applicable debtor.

2.	Summary of Significant Accounting Policies	

 	NRG Energy Fresh Start Reporting/Push Down Accounting	
      In accordance with SOP 90-7, certain companies qualify for fresh start (“Fresh Start”) reporting in connection with their emergence from bankruptcy. Fresh Start reporting is appropriate on the emergence from Chapter 11 if the reorganization value of the assets of the emerging entity immediately before the date of confirmation is less than the total of all post-petition liabilities and allowed claims, and if the holders of existing voting shares immediately before confirmation receive less than 50% of the voting shares of the emerging entity. NRG Energy met these requirements and adopted Fresh Start reporting and applied push down accounting to its various subsidiary operations including the Company. Under push down accounting, the Company’s equity fair value was allocated to the Company’s assets and liabilities based on their estimated fair values as of December 5, 2003, as further described in Note 3.

      Under the requirements of Fresh Start, NRG Energy adjusted its assets and liabilities, other than deferred income taxes, to their estimated fair values as of December 5, 2003. As a result of marking the assets and liabilities to their estimated fair values, NRG Energy determined that there was a negative reorganization value that was reallocated back to the tangible and intangible assets. Deferred taxes were determined in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 109,  Accounting for Income Taxes . The net effect of all Fresh Start adjustments resulted in a gain of $3.9 billion, which is reflected in NRG Energy’s Predecessor Company results for the period from January 1, 2003 to December 5, 2003. The application of the Fresh Start provisions of SOP 90-7 created a new reporting entity having no retained earnings or accumulated deficit.

      As part of the bankruptcy process, NRG Energy engaged an independent financial advisor to assist in the determination of its reorganized enterprise value. The fair value calculation was based on management’s forecast of expected cash flows from its core assets. Management’s forecast incorporated forward commodity market prices obtained from a third party consulting firm. A discounted cash flow calculation was used to develop the enterprise value of Reorganized NRG, determined in part by calculating the weighted average

9

 
NRG EASTERN LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

cost of capital of the Reorganized NRG. The Discounted Cash Flow, (“DCF,”) valuation methodology equates the value of an asset or business to the present value of expected future economic benefits to be generated by that asset or business. The DCF methodology is a “forward looking” approach that discounts expected future economic benefits by a theoretical or observed discount rate. The independent financial advisor prepared a 30-year cash flow forecast using a discount rate of approximately 11%. The resulting reorganization enterprise value as included in the Disclosure Statement ranged from $5.5 billion to $5.7 billion. The independent financial advisor then subtracted NRG Energy’s project level debt and made several other adjustments to reflect the values of assets held for sale, excess cash and collateral requirements to estimate a range of Reorganized NRG equity value of between $2.2 billion and $2.6 billion.

      In constructing the Fresh Start balance sheet upon emergence from bankruptcy, NRG Energy used a reorganization equity value of approximately $2.4 billion, as NRG Energy believed this value to be the best indication of the value of the ownership distributed to the new equity owners. NRG Energy’s Plan of Reorganization provided for the issuance of 100,000,000 shares of NRG Energy common stock to the various creditors resulting in a calculated price per share of $24.04. The reorganization value of approximately $9.1 billion was determined by adding the reorganized equity value of $2.4 billion, $3.7 billion of interest bearing debt and other liabilities of $3.0 billion. The reorganization value represents the fair value of an entity before liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after restructuring. This value is consistent with the voting creditors and Court’s approval of NRG Energy’s Plan of Reorganization.

      The application of SOP 90-7 and push down accounting resulted in the creation of a new reporting entity for the Company. Consequently, the financial statements of the Reorganized Company and the Predecessor Company are separated by a black line to distinguish that the assets, liabilities and member’s equity as well as the results of operations are not comparable between periods. Under the requirements of push down accounting, the Company has adjusted its assets and liabilities to their estimated fair values as of December 5, 2003. The impact of push down accounting resulted in the reduction of member’s equity for the Company in the amount of $10.1 million.

      For financial reporting purposes, close of business on December 5, 2003, represents the date of NRG Energy’s emergence from bankruptcy. As used herein, the following terms refer to the Company and its operations:
 	 	 	
“Predecessor Company”	 	The Company, prior to push down accounting	
 	 	The Company’s operations, January 1, 2001 - December 31, 2001	
 	 	The Company’s operations, January 1, 2002 - December 31, 2002	
 	 	The Company’s operations, January 1, 2003 - December 5, 2003	
“Reorganized Company”	 	The Company, post push down accounting	
 	 	The Company’s operations, December 6, 2003 - December 31, 2003	
      The bankruptcy court in its confirmation order approved NRG Energy’s Plan of Reorganization on November 24, 2003, and subsequently approved the Northeast/ South Central Plan of Reorganization on November 25, 2003. Under the requirements of SOP 90-7, the Fresh Start date is determined to be the confirmation date unless significant uncertainties exist regarding the effectiveness of the bankruptcy order. NRG Energy’s Plan of Reorganization required completion of the Xcel Energy settlement agreement prior to emergence from bankruptcy. Management believes this settlement agreement was a significant contingency and thus delayed the Fresh Start date until the Xcel Energy settlement agreement was finalized on December 5, 2003.

10

 
NRG EASTERN LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

 	Investment Impairments	
      Investments accounted for by the equity method are reviewed for impairment in accordance with APB Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock . APB Opinion No. 18 requires that a loss in value of an investment that is other than a temporary decline should be recognized. The Company identifies and measures losses in value of equity investments based upon a comparison of fair value to carrying value.

 	Investment in Affiliate	
      The Company’s investment in Northeast Gen is accounted for under the equity method of accounting. The initial investment was recorded at cost and its carrying value is adjusted to recognize the Company’s share of earnings or losses and dividends.

 	Equity Earnings	
      Earnings are recognized under the equity method of accounting in which the Company recognizes its share of the earnings or losses of the equity affiliate in the periods for which they are reported in the affiliate’s financial statements. Equity earnings are recorded before income taxes of the equity affiliate with the appropriate income taxes recorded as a component of the Company’s income tax provision.

 	Income Taxes	
      The Company has been organized as a limited liability company. Therefore, federal and state income taxes are assessed at the member level. However, a separate company provision for federal and state income taxes has been reflected in the accompanying financial statements (see Note 7 — Income Taxes). As a result of the Company being included in the NRG Energy consolidated tax return and tax payments, federal and state taxes payable amounts resulting from the tax provision are reflected as a contribution by member in the statement of member’s equity and balance sheet.

      Deferred income taxes are recognized for the tax consequences in future years of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts at each year end based on enacted tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. Income tax expense is the tax payable for the period and the change during the period in deferred tax assets and liabilities. A valuation allowance is recorded to reduce deferred tax assets to the amount more likely than not to be realized.

 	Use of Estimates in Financial Statements	
      The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenue and expenses during the reporting period. Actual results could differ from these estimates.

3.	Emergence from Bankruptcy and Fresh Start Reporting	
      In accordance with the requirements of push down accounting, the Company’s fair value of $325.3 million was allocated to the Company’s assets and liabilities based on their individual estimated fair values. A third party was used to complete an independent appraisal of the Company’s tangible assets, intangible assets and contracts.

      The determination of the fair value of the Company’s assets and liabilities was based on a number of estimates and assumptions, which are inherently subject to significant uncertainties and contingencies.

11

 
NRG EASTERN LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

      Due to the adoption of push down accounting as of December 5, 2003, the Reorganized Company’s balance sheets, statements of operations and cash flows have not been prepared on a consistent basis with the Predecessor Company’s financial statements and are not comparable in certain respects to the financial statements prior to the application of push down accounting. A black line has been drawn on the accompanying financial statements to separate and distinguish between the Reorganized Company and the Predecessor Company. The effects of the push down accounting adjustments on the Company’s balance sheet as of December 5, 2003, were as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor	 	 	 	Reorganized	
 	 	Company	 	 	 	Company	
 	 	December 5,	 	Push down	 	December 6,	
 	 	2003	 	Adjustments	 	2003	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
ASSETS	
Investment in affiliate	 	$	301,719	 	 	$	(22,107	)(A)	 	$	279,612	 	
Noncurrent deferred income tax	 	 	33,684	 	 	 	12,032	 (B)	 	 	45,716	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total assets	 	$	335,403	 	 	$	(10,075	)	 	$	325,328	 	

	 	 	 	

	 	 	 	

	 	
 	
LIABILITIES AND MEMBER’S EQUITY	
Member’s equity	 	 	 	 	 	 	 	 	 	 	 	 	
 	Member’s contributions	 	$	374,643	 	 	$	(49,315	)	 	$	325,328	 	
 	Accumulated net loss	 	 	(39,240	)	 	 	39,240	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total member’s equity	 	 	335,403	 	 	 	(10,075	)(C)	 	 	325,328	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total liabilities and member’s equity	 	$	335,403	 	 	$	(10,075	)	 	$	325,328	 	

	 	 	 	

	 	 	 	

	 	

 
 	 	 	
(A)	 	Result of allocating the equity value in conformity with the purchase method of accounting for business combinations. These allocations were based on valuations obtained from independent appraisers	
 	 	 	
(B)	 	Reflects the adjustment to deferred income tax assets and liabilities due to push down accounting.	
 	 	 	
(C)	 	The changes in member’s equity reflect the fair value adjustment resulting from NRG Energy’s accounting procedures.	

4.	Derivative Instruments and Hedging Activity	
      On January 1, 2001, the Company adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 137, SFAS No. 138 and SFAS No. 149. SFAS No. 133 requires the Company to record all derivatives on the balance sheet at fair value. Changes in the fair value of nonhedge derivatives will be immediately recognized in earnings. The criteria used to determine if hedge accounting treatment is appropriate are (a) the designation of the hedge to an underlying exposure, (b) whether or not the overall risk is being reduced and (c) if there is high degree of correlation between the value of the derivative instrument and the underlying obligation. Formal documentation of the hedging relationship, the nature of the underlying risk, the risk management objective, and the means by which effectiveness will be assessed is created at the inception of the hedge. Changes in fair values of derivatives accounted for as hedges will either be recognized in earnings as offsets to the changes in fair value of related hedged assets, liabilities and firm commitments or, for forecasted transactions, deferred and recorded as a component of other accumulated comprehensive income, (“OCI,”) until the hedged transactions occur and are recognized in earnings. The ineffective portion of a hedging derivative instrument’s change in fair value will be immediately recognized in earnings. The Company also formally assesses both at inception and at least quarterly thereafter, whether the derivatives that are used in hedging transactions are highly effective in offsetting the changes in either the fair value or cash flows of the hedged item. This assessment includes all

12

 
NRG EASTERN LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

components of each derivative’s gain or loss unless otherwise noted. When it is determined that a derivative ceases to be a highly effective hedge, hedge accounting is discontinued.

      SFAS No. 133 applies to the Northeast Gen’s long-term power sales contracts, long-term gas contracts and other energy related commodities financial instruments used to mitigate variability in earnings due to the fluctuations in spot market prices, hedge fuel requirements at generation facilities and protect investments in fuel inventories. At December 31, 2003, Northeast Gen had various commodity contracts extending through April 2004.

 	Accumulated Other Comprehensive Income	
      The following table summarizes the effects of SFAS No. 133 on the Company’s accumulated other comprehensive income balance at December 31, 2003, December 6, 2003 and December 31, 2002, respectively:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the	
 	 	2003 to	 	2003 to	 	Year Ended	
 	 	December 31,	 	December 5,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Energy Commodities Gains (Losses)	 	 	 	 	 	 	 	 	 	 	 	 	
Beginning balance	 	$	—	 	 	$	14,418	 	 	$	53,871	 	
 	Unwound from OCI during period	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Due to unwinding of previously deferred amounts	 	 	—	 	 	 	(14,418	)	 	 	(24,043	)	
 	Mark to market of hedge contracts	 	 	—	 	 	 	—	 	 	 	(15,410	)	

	 	 	 	

	 	 	 	

	 	
Ending balance	 	$	—	 	 	$	—	 	 	$	14,418	 	

	 	 	 	

	 	 	 	

	 	
Gains expected to unwind from OCI during next 12 months	 	$	—	 	 	$	—	 	 	$	14,418	 	
      During the periods from January 1, 2003 to December 5, 2003, and the year ended December 31, 2002, the Company reclassified gains of $14.4 million and $24.0 million, respectively, from OCI to current-period earnings. This amount is recorded on the same line in the statement of operations in which the hedged item is recorded. Also during the year ended December 31, 2002, the Company recorded losses in OCI of approximately $15.4 million related to changes in the fair values of derivatives accounted for as hedges. The net balance in OCI relating to SFAS No. 133 at December 31, 2002, was a gain of approximately $14.4 million.

5.	Guarantees	
      In November 2002, the FASB issued FIN 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.  The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor’s fiscal year end. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002. The interpretation addresses the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees. The interpretation also clarifies the requirements related to the recognition of a liability by a guarantor at the inception of the guarantee for the obligations the guarantor has undertaken in issuing the guarantee.

13

 
NRG EASTERN LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

      In connection with push down accounting, all outstanding guarantees were considered new; accordingly, the Company applied the provision of FIN 45 to all of those guarantees. Each guarantee was reviewed for the requirement to recognize a liability at inception.

      Northeast Gen and the Company are guarantors under the debt issued by the Company’s parent, NRG Energy. NRG Energy issued $1.25 billion of 8% Second Priority Notes on December 23, 2003, due and payable on December 15, 2013. On January 28, 2004, NRG Energy also issued $475.0 million of Second Priority Notes, under the same terms and indenture as its December 23, 2003 offering.

      NRG Energy’s payment obligations under the notes and all related parity lien obligations are guaranteed on an unconditional basis by each of NRG Energy’s current and future restricted subsidiaries, of which the Company is one. The notes are jointly and severally guaranteed by each of the guarantors. The subsidiary guarantees of the notes are secured, on a second priority basis, equally and ratably with any future parity lien debt, by security interests in all of the assets of the guarantors, except certain excluded assets, subject to liens securing parity lien debt and other permitted prior liens.

      The Company’s obligations pursuant to its guarantees of the performance, equity and indebtedness obligations were as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantee/	 	 	 	 	 	 	
 	 	Maximum	 	 	 	Expiration	 	 	
 	 	Exposure	 	Nature of Guarantee	 	Date	 	Triggering Event	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
NRG Energy Second Priority Notes due 2013	 	$	1,753,000	 	 	Obligations under credit agreement	 	 	2013	 	 	 	Nonperformance	 	

6.	Investments Accounted for by the Equity Method	
      The Company has a 50% equity investment in Northeast Gen which owns electric power generation plants in the northeast region of the United States. Northeast Generation Holding LLC owns the remaining 50% interest in Northeast Gen. The equity method of accounting is applied to such investments in affiliates, which include joint ventures and partnerships because the ownership structure prevents the Company from exercising a controlling influence over operating and financial policies of the projects. Under this method, equity in the pre-tax income or losses of such projects are reflected as equity in earnings of unconsolidated affiliates.

      Summarized financial information of the Company’s only unconsolidated affiliate, Northeast Gen, without the impact of income taxes recorded is as follows:

      Results of operations:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Operating revenues	 	$	60,471	 	 	$	730,463	 	 	$	693,869	 	 	$	1,050,688	 	
Costs and expenses	 	 	50,165	 	 	 	985,974	 	 	 	689,984	 	 	 	839,433	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Net income (loss) before taxes	 	$	10,306	 	 	$	(255,511	)	 	$	3,885	 	 	$	211,255	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
14

 
NRG EASTERN LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

      Financial position:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Current assets	 	$	162,283	 	 	$	171,621	 	 	$	317,818	 	
Other assets	 	 	1,064,874	 	 	 	1,067,437	 	 	 	1,375,919	 	

	 	 	 	

	 	 	 	

	 	
 	Total assets	 	$	1,227,157	 	 	$	1,239,058	 	 	$	1,693,737	 	

	 	 	 	

	 	 	 	

	 	
Current liabilities	 	$	84,149	 	 	$	672,345	 	 	$	678,679	 	
Other liabilities	 	 	7,528	 	 	 	7,493	 	 	 	35,495	 	
Member’s equity	 	 	1,135,480	 	 	 	559,220	 	 	 	979,563	 	

	 	 	 	

	 	 	 	

	 	
 	Total liabilities and member’s equity	 	$	1,227,157	 	 	$	1,239,058	 	 	$	1,693,737	 	

	 	 	 	

	 	 	 	

	 	

7.	Income Taxes	
      The Company is included in the consolidated tax return filings as a wholly owned subsidiary of NRG Energy. Reflected in the financial statements and notes below are separate company federal and state tax provisions as if the Company had prepared separate filings. An income tax provision has been established on the accompanying financial statements as of the earliest period presented in order to reflect income taxes as if the Company filed its own tax return. The Company’s parent, NRG Energy, does not have a tax allocation agreement with its subsidiaries and prior to January 1, 2003, income taxes were not recorded or allocated to non tax paying entities or entities such as the Company which are treated as disregarded entities for tax purposes. Because the Company is not a party to a tax sharing agreement, current tax expense (benefit) is recorded as a capital contribution from (distribution to) the Company’s parent. The cumulative effect of recording an income tax provision (benefit) and deferred taxes resulted in recording as of December 31, 2000, a net deferred tax liability of $32.1 million and a reduction to member’s equity of $32.1 million.

15

 
NRG EASTERN LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

      The provision (benefit) for income taxes consists of the following:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December	 	

	
 	 	2003	 	5, 2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Current	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Federal	 	$	1,479	 	 	$	5,695	 	 	$	5,998	 	 	$	29,921	 	
 	State	 	 	591	 	 	 	2,278	 	 	 	2,399	 	 	 	11,968	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	2,070	 	 	 	7,973	 	 	 	8,397	 	 	 	41,889	 	
Deferred	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Federal	 	 	114	 	 	 	(44,919	)	 	 	(4,811	)	 	 	2,711	 	
 	State	 	 	46	 	 	 	(17,966	)	 	 	(1,924	)	 	 	1,084	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	160	 	 	 	(62,885	)	 	 	(6,735	)	 	 	3,795	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Total income tax expense (benefit)	 	$	2,230	 	 	$	(54,912	)	 	$	1,662	 	 	$	45,684	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Effective tax rate	 	 	43.2	%	 	 	43.0	%	 	 	93.2	%	 	 	43.3	%	
      The pre-tax income (loss) was as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December	 	

	
 	 	2003	 	5, 2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
U.S. 	 	$	5,153	 	 	$	(127,756	)	 	$	1,784	 	 	$	105,530	 	
      The components of the net deferred income tax (assets) liabilities were:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Investment in project	 	$	—	 	 	$	—	 	 	$	29,198	 	

	 	 	 	

	 	 	 	

	 	
 	Total deferred tax liabilities	 	 	—	 	 	 	—	 	 	 	29,198	 	
Deferred tax assets	 	 	 	 	 	 	 	 	 	 	 	 	
 	Investment in project	 	 	45,556	 	 	 	45,716	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total deferred tax assets (before valuation allowance)	 	 	45,556	 	 	 	45,716	 	 	 	—	 	
Valuation allowance	 	 	—	 	 	 	—	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
Net deferred tax assets	 	 	45,556	 	 	 	45,716	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
Net deferred tax (assets) liabilities	 	$	(45,556	)	 	$	(45,716	)	 	$	29,198	 	

	 	 	 	

	 	 	 	

	 	
16

 
NRG EASTERN LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

      The net deferred tax (assets) liabilities consists of:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Current deferred tax liabilities	 	$	—	 	 	$	—	 	 	$	—	 	
Noncurrent deferred tax (assets) liabilities	 	 	(45,556	)	 	 	(45,716	)	 	 	29,198	 	

	 	 	 	

	 	 	 	

	 	
Net deferred tax (assets) liabilities	 	$	(45,556	)	 	$	(45,716	)	 	$	29,198	 	

	 	 	 	

	 	 	 	

	 	
      The effective income tax rates of continuing operations differ from the statutory federal income tax rate of 35% as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	 	 	 	 	
 	 	Company	 	 	 	Predecessor Company	 	 	

	 	 	 	

	 	 	
 	 	For the	 	 	 	For the	 	 	 	 	
 	 	Period from	 	 	 	Period from	 	 	 	 	 	 	
 	 	December 6,	 	 	 	January 1,	 	 	 	For the Years Ended	 	 	
 	 	2003 to	 	 	 	2003 to	 	 	 	December 31,	 	 	
 	 	December 31,	 	 	 	December 5,	 	 	 	

	 	 	
 	 	2003	 	 	 	2003	 	 	 	2002	 	 	 	2001	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	
 	 	 	
 	 	(In thousands of dollars)	
Income (loss) before taxes	 	$	5,153	 	 	 	 	 	 	$	(127,756	)	 	 	 	 	 	$	1,784	 	 	 	 	 	 	$	105,530	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	
Tax at 35%	 	 	1,804	 	 	 	35.0	%	 	 	(44,715	)	 	 	35.0	%	 	 	624	 	 	 	35.0%	 	 	 	36,936	 	 	 	35.0%	 	
State taxes (net of federal benefit)	 	 	414	 	 	 	8.0	%	 	 	(10,197	)	 	 	8.0	%	 	 	309	 	 	 	17.3%	 	 	 	8,484	 	 	 	8.0%	 	
Other	 	 	12	 	 	 	0.2	%	 	 	—	 	 	 	—	 	 	 	729	 	 	 	40.9%	 	 	 	264	 	 	 	0.3%	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	
Income tax expense (benefit)	 	$	2,230	 	 	 	43.2	%	 	$	(54,912	)	 	 	43	%	 	$	1,662	 	 	 	93.2%	 	 	$	45,684	 	 	 	43.3%	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	

8.	Commitments and Contingencies	
      In the normal course of business, the Company is subject to various claims and litigation. Management of the Company expects that these various litigation items will not have a material adverse effect on the results of operations or financial position of the Company.

17

 

EXHIBIT 99.8

NORTHEAST GENERATION HOLDING LLC

FINANCIAL STATEMENTS

At December 31, 2003, December 6, 2003 and
December 31, 2002, and for the Period from
December 6, 2003 to December 31, 2003, the Period
from January 1, 2003 to December 5, 2003 and for
the Years Ended December 31, 2002 and 2001

 

NORTHEAST GENERATION HOLDING LLC

INDEX
 	 	 	 	 	
 	 	Page(s)	

	
Reports of Independent Auditors	 	 	2-3	 	
 	
Financial Statements	 	 	 	 	
Balance Sheets at December 31, 2003, December 6, 2003 and December 31, 2002	 	 	4	 	
Statements of Operations for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001	 	 	5	 	
Statements of Member’s Equity for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001	 	 	6	 	
Statements of Cash Flows for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001	 	 	7	 	
Notes to Financial Statements	 	 	8-10	 	
1

 

REPORT OF INDEPENDENT AUDITORS

To the Member of
Northeast Generation Holding LLC

      In our opinion, the accompanying balance sheet and the related statements of operations, of member’s equity, and of cash flows present fairly, in all material respects, the financial position of Northeast Generation Holding LLC (“Predecessor Company”) at December 31, 2002, and the results of its operations and its cash flows for the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      As discussed in Note 1 to the financial statements, on May 14, 2003, NRG Energy, Inc. and certain of its subsidiaries including the Company, filed a petition with the United States Bankruptcy Court for the Southern District of New York for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. NRG Energy, Inc.’s Plan of Reorganization was substantially consummated on December 5, 2003, and Reorganized NRG emerged from bankruptcy. The Company emerged from bankruptcy on December 23, 2003, pursuant to a separate plan of reorganization referred to as the Northeast/ South Central Plan of Reorganization. The impact of NRG Energy, Inc.’s emergence from bankruptcy and fresh start accounting was applied to the Company on December 5, 2003 under push down accounting methodology.
 	 	
 	/s/ PRICEWATERHOUSECOOPERS LLP	

	
 	PricewaterhouseCoopers LLP	
Minneapolis, Minnesota
March 10, 2004

2

 

REPORT OF INDEPENDENT AUDITORS

To the Member of
Northeast Generation Holding LLC

      In our opinion, the accompanying balance sheets and the related statements of operations, of member’s equity, and of cash flows present fairly, in all material respects, the financial position of NRG Northeast Generation Holding LLC (“Reorganized Company”) at December 31, 2003 and December 6, 2003, and the results of its operations and its cash flows for the period from December 6, 2003 to December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      As discussed in Note 1 to the financial statements, on May 14, 2003, NRG Energy, Inc. and certain of its subsidiaries including the Company, filed a petition with the United States Bankruptcy Court for the Southern District of New York for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. NRG Energy, Inc.’s Plan of Reorganization was substantially consummated on December 5, 2003, and Reorganized NRG emerged from bankruptcy. The Company emerged from bankruptcy on December 23, 2003, pursuant to a separate plan of reorganization referred to as the Northeast/ South Central Plan of Reorganization. The impact of NRG Energy, Inc.’s emergence from bankruptcy and fresh start accounting was applied to the Company on December 5, 2003 under push down accounting methodology.
 	 	
 	/s/ PRICEWATERHOUSECOOPERS LLP	

	
 	PricewaterhouseCoopers LLP	
Minneapolis, Minnesota
March 10, 2004

3

 

NORTHEAST GENERATION HOLDING LLC

BALANCE SHEETS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
ASSETS	
Investment in affiliate	 	$	567,740	 	 	$	279,612	 	 	$	489,779	 	
Noncurrent deferred income tax	 	 	45,556	 	 	 	45,716	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total assets	 	$	613,296	 	 	$	325,328	 	 	$	489,779	 	

	 	 	 	

	 	 	 	

	 	
 	
LIABILITIES AND MEMBER’S EQUITY	
Current liabilities	 	 	 	 	 	 	 	 	 	 	 	 	
 	Accounts payable — affiliates	 	$	5	 	 	$	—	 	 	$	—	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total current liabilities	 	 	5	 	 	 	—	 	 	 	—	 	
Noncurrent deferred income tax	 	 	—	 	 	 	—	 	 	 	29,198	 	
Commitments and contingencies	 	 	 	 	 	 	 	 	 	 	 	 	
Member’s equity	 	 	613,291	 	 	 	325,328	 	 	 	460,581	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total liabilities and member’s equity	 	$	613,296	 	 	$	325,328	 	 	$	489,779	 	

	 	 	 	

	 	 	 	

	 	
The accompanying notes are an integral part of these financial statements.

4

 

NORTHEAST GENERATION HOLDING LLC

STATEMENTS OF OPERATIONS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
General and administrative expense	 	$	5	 	 	$	—	 	 	$	—	 	 	$	—	 	
Equity earnings (losses) in unconsolidated affiliate	 	 	5,153	 	 	 	(127,755	)	 	 	1,942	 	 	 	105,627	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	Income (loss) before income taxes	 	 	5,148	 	 	 	(127,755	)	 	 	1,942	 	 	 	105,627	 	
Income tax expense (benefit)	 	 	2,228	 	 	 	(54,912	)	 	 	1,731	 	 	 	45,725	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	Net income (loss)	 	$	2,920	 	 	$	(72,843	)	 	$	211	 	 	$	59,902	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
The accompanying notes are an integral part of these financial statements.

5

 

NORTHEAST GENERATION HOLDING LLC

STATEMENTS OF MEMBER’S EQUITY
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	Accumulated	 	 	
 	 	Member	 	Member	 	Accumulated	 	Other	 	Total	

	 	Contributions/	 	Net Income	 	Comprehensive	 	Member’s	
 	 	Units	 	Amount	 	Distributions	 	(Loss)	 	Income	 	Equity	

	 	

	 	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Balances at December 31, 2000 (Predecessor Company)	 	 	1,000	 	 	$	1	 	 	$	362,017	 	 	$	—	 	 	$	—	 	 	$	362,018	 	
Cumulative effect upon adoption of SFAS No. 133	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	7,050	 	 	 	7,050	 	
Impact of SFAS No. 133 for the year ending December 31, 2001	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	46,820	 	 	 	46,820	 	
Net income	 	 	 	 	 	 	 	 	 	 	—	 	 	 	59,902	 	 	 	—	 	 	 	59,902	 	

	 	
Comprehensive income	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	113,772	 	
Contribution from member	 	 	—	 	 	 	—	 	 	 	41,930	 	 	 	—	 	 	 	—	 	 	 	41,930	 	
Distribution to member	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(26,363	)	 	 	—	 	 	 	(26,363	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Balances at December 31, 2001 (Predecessor Company)	 	 	1,000	 	 	 	1	 	 	 	403,947	 	 	 	33,539	 	 	 	53,870	 	 	 	491,357	 	
Impact of SFAS No. 133 for the year ending December 31, 2002	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(39,453	)	 	 	(39,453	)	
Net income	 	 	—	 	 	 	—	 	 	 	—	 	 	 	211	 	 	 	—	 	 	 	211	 	

	 	
Comprehensive loss	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(39,242	)	
Contribution from member	 	 	—	 	 	 	—	 	 	 	8,466	 	 	 	—	 	 	 	—	 	 	 	8,466	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Balances at December 31, 2002 (Predecessor Company)	 	 	1,000	 	 	 	1	 	 	 	412,413	 	 	 	33,750	 	 	 	14,417	 	 	 	460,581	 	
Impact of SFAS No. 133 for the period ending December 5, 2003	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(14,417	)	 	 	(14,417	)	
Net loss	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(72,843	)	 	 	—	 	 	 	(72,843	)	

	 	
Comprehensive loss	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(87,260	)	
Distribution to member	 	 	—	 	 	 	—	 	 	 	(45,888	)	 	 	—	 	 	 	—	 	 	 	(45,888	)	
Contribution from member	 	 	—	 	 	 	—	 	 	 	7,973	 	 	 	—	 	 	 	—	 	 	 	7,973	 	
Balance at December 5, 2003 (Predecessor Company)	 	 	1,000	 	 	 	1	 	 	 	374,498	 	 	 	(39,093	)	 	 	—	 	 	 	335,406	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Pushdown accounting adjustments	 	 	—	 	 	 	—	 	 	 	(49,171	)	 	 	39,093	 	 	 	—	 	 	 	(10,078	)	
Balances at December 6, 2003 (Reorganized Company)	 	 	1,000	 	 	 	1	 	 	 	325,327	 	 	 	—	 	 	 	—	 	 	 	325,328	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Contribution from member	 	 	—	 	 	 	—	 	 	 	285,043	 	 	 	—	 	 	 	—	 	 	 	285,043	 	
Net income	 	 	—	 	 	 	—	 	 	 	—	 	 	 	2,920	 	 	 	—	 	 	 	2,920	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Balances at December 31, 2003 (Reorganized Company)	 	 	1,000	 	 	$	1	 	 	$	610,370	 	 	$	2,920	 	 	$	—	 	 	$	613,291	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
The accompanying notes are an integral part of these financial statements.

6

 

NORTHEAST GENERATION HOLDING LLC

STATEMENTS OF CASH FLOWS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Cash flows from operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	$	2,920	 	 	$	(72,843	)	 	$	211	 	 	$	59,902	 	
Adjustments to reconcile net income (loss) to net cash provided by operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Distributions (less than) in excess of equity earnings/ losses of unconsolidated affiliate	 	 	(5,153	)	 	 	127,755	 	 	 	(1,941	)	 	 	(79,264	)	
 	Deferred income taxes	 	 	160	 	 	 	(62,885	)	 	 	(6,736	)	 	 	3,795	 	
 	Current tax expense — noncash contribution from member	 	 	2,068	 	 	 	7,973	 	 	 	8,466	 	 	 	41,930	 	
 	Changes in assets and liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Accounts payable — affiliates	 	 	5	 	 	 	—	 	 	 	—	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	Net cash provided by operating activities	 	 	—	 	 	 	—	 	 	 	—	 	 	 	26,363	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Cash flows from investing activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Investment in affiliate	 	 	(282,975	)	 	 	—	 	 	 	—	 	 	 	—	 	
Dividends received from investment	 	 	—	 	 	 	45,888	 	 	 	—	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	Net cash (used in) provided by investing activities	 	 	(282,975	)	 	 	45,888	 	 	 	—	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Cash flows from financing activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Distribution to member	 	 	—	 	 	 	(45,888	)	 	 	—	 	 	 	(26,363	)	
Contribution from member	 	 	282,975	 	 	 	—	 	 	 	—	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	Net cash provided by (used in) financing activities	 	 	282,975	 	 	 	(45,888	)	 	 	—	 	 	 	(26,363	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	Net change in cash and cash equivalents	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Cash and cash equivalents	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Beginning of period	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
End of period	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Supplement disclosures of cash flow information	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Noncash contribution from member for current tax expense	 	$	2,068	 	 	$	7,973	 	 	$	8,466	 	 	$	41,930	 	
The accompanying notes are an integral part of these financial statements.

7

 

NORTHEAST GENERATION HOLDING LLC

NOTES TO FINANCIAL STATEMENTS

1.     Organization

      Northeast Generation Holding LLC (the “Company”), a directly held wholly owned subsidiary of NRG Energy, Inc. (“NRG Energy”), primarily holds a 50% equity interest in NRG Northeast Generating LLC (“Northeast Gen”) which owns electric power generation plants in the northeastern region of the United States. Northeast Gen was formed in 1999 for the purpose of financing, acquiring, owning, operating and maintaining, through its subsidiaries and affiliates the facilities owned by Arthur Kill Power LLC, Astoria Gas Turbine Power LLC, Connecticut Jet Power LLC, Devon Power LLC, Dunkirk Power LLC, Huntley Power LLC, Middletown Power LLC, Montville Power LLC, Norwalk Power LLC, Oswego Harbor Power LLC and Somerset Power LLC.

     Recent Developments

      On May 14, 2003, NRG Energy and 25 of its direct and indirect wholly owned subsidiaries commenced voluntary petitions under Chapter 11 of the bankruptcy code in the United States Bankruptcy Court for the Southern District of New York. Northeast Gen was included in the Chapter 11 filing. During the bankruptcy proceedings, NRG Energy continued to conduct business and manage the companies as debtors in possession pursuant to sections 1107(a) and 1108 of the bankruptcy code. Two plans of reorganization were filed in connection with the restructuring efforts. The first, filed on May 14, 2003, and referred to as NRG Energy’s Plan of Reorganization, relates to NRG Energy and the other NRG Energy plan debtors. The second plan, relating to the Company, Northeast Gen and, its subsidiaries and the South Central subsidiaries, referred to as the Northeast/ South Central Plan of Reorganization, was filed on September 17, 2003. On November 24, 2003, the bankruptcy court entered an order confirming NRG Energy’s Plan of Reorganization and the plan became effective on December 5, 2003. On November 25, 2003, the bankruptcy court issued an order confirming the Northeast/ South Central Plan of Reorganization and the plan became effective on December 23, 2003. In connection with NRG Energy’s emergence from bankruptcy, NRG Energy adopted fresh start reporting in accordance with AICPA Statement of Position 90-7,  Financial Reporting by Entities in Reorganization Under the Bankruptcy code  (“SOP 90-7) on December 5, 2003. NRG Energy’s fresh start reporting was applied to the Company on a push down accounting basis with the financial statement impact recorded as an adjustment to the December 6, 2003, member’s equity in the amount of $10.1 million.

     NRG Energy’s Plan of Reorganization

      NRG Energy’s Plan of Reorganization is the result of several months of intense negotiations among NRG Energy, Xcel Energy, Inc. (“Xcel Energy”) and the two principal committees representing NRG Energy creditor groups, referred to as the Global Steering Committee and the Noteholder Committee. A principal component of NRG Energy’s Plan of Reorganization is a settlement with Xcel Energy in which Xcel Energy agreed to make a contribution consisting of cash (and, under certain circumstances, its stock) in the aggregate amount of up to $640 million to be paid in three separate installments following the effective date of NRG Energy’s Plan of Reorganization. The Xcel Energy settlement agreement resolves any and all claims existing between Xcel Energy and NRG Energy and/or its creditors and, in exchange for the Xcel Energy contribution, Xcel Energy is receiving a complete release of claims from NRG Energy and its creditors, except for a limited number of creditors who have preserved their claims as set forth in the confirmation order entered on November 24, 2003.

     Northeast/ South Central Plan of Reorganization

      The Northeast/ South Central Plan of Reorganization was proposed on September 17, 2003, after the necessary financing commitments were secured. On November 25, 2003, the bankruptcy court issued an order confirming the Northeast/ South Central Plan of Reorganization and the plan became effective on December 23, 2003. In connection with the order confirming the Northeast/ South Central Plan of Reorganization,

8

 
NORTHEAST GENERATION HOLDING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

the court entered a separate order which provides that the allowed amount of the bondholders’ claims shall equal in the aggregate the sum of (i) $1.3 billion plus (ii) any accrued and unpaid interest at the applicable contract rates through the date of payment to the indenture trustee plus (iii) the reasonable fees, costs or expenses of the collateral agent and indenture trustee (other than reasonable professional fees incurred from October 1, 2003) plus (iv) $19.6 million, ratably, for each holder of bonds based upon the current outstanding principal amount of the bonds and irrespective of (a) the date of maturity of the bonds, (b) the interest rate applicable to such bonds and (c) the issuer of the bonds. The settlement further provides that the Northeast/ South Central debtors shall reimburse the informal committee of secured bondholders, the indenture trustee, the collateral agent, and two additional bondholder groups, for any reasonable professional fees, costs or expenses incurred from October 1, 2003 through January 31, 2004, up to a maximum amount of $2.5 million (including in such amount any post-October 1, 2003 fees already reimbursed), with the exception that the parties to the settlement reserved their respective rights with respect to any additional reasonable fees, costs or expenses incurred subsequent to November 25, 2003, related to matters not reasonably contemplated by the implementation of the settlement of the Northeast/ South Central Plan of Reorganization.

      The creditors of Northeast and South Central subsidiaries were unimpaired by the Northeast/ South Central Plan of Reorganization. The creditors holding allowed general secured claims were paid in cash, in full on the effective date of the Northeast/ South Central Plan of Reorganization. Holders of allowed unsecured claims will receive or have received either (i) cash equal to the unpaid portion of their allowed unsecured claims, (ii) treatment that leaves unaltered the legal, equitable and contractual rights to which such unsecured claims entitle the holder of such claims, (iii) treatment that otherwise renders such unsecured claims unimpaired pursuant to section 1124 of the bankruptcy code or (iv) such other, less favorable treatment that is confirmed in writing as being acceptable to such holder and to the applicable debtor.

2.	Summary of Significant Accounting Policies	
     NRG Energy Fresh Start Reporting/Push Down Accounting

      In accordance with SOP 90-7, certain companies qualify for fresh start (Fresh Start”) reporting in connection with their emergence from bankruptcy. Fresh Start reporting is appropriate on the emergence from Chapter 11 if the reorganization value of the assets of the emerging entity immediately before the date of confirmation is less than the total of all post-petition liabilities and allowed claims, and if the holders of existing voting shares immediately before confirmation receive less than 50% of the voting shares of the emerging entity. NRG Energy met these requirements and adopted Fresh Start reporting and applied push down accounting to its various subsidiary operations including the Company. Under push down accounting, the Company’s equity fair value was allocated to the Company’s assets and liabilities based on their estimated fair values as of December 5, 2003, as further described in Note 3.

      Under the requirements of Fresh Start, NRG Energy adjusted its assets and liabilities, other than deferred income taxes, to their estimated fair values as of December 5, 2003. As a result of marking the assets and liabilities to their estimated fair values, NRG Energy determined that there was a negative reorganization value that was reallocated back to the tangible and intangible assets. Deferred taxes were determined in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 109,  Accounting for Income Taxes . The net effect of all Fresh Start adjustments resulted in a gain of $3.9 billion, which is reflected in NRG Energy’s Predecessor Company results for the period from January 1, 2003 to December 5, 2003. The application of the Fresh Start provisions of SOP 90-7 created a new reporting entity having no retained earnings or accumulated deficit.

      As part of the bankruptcy process, NRG Energy engaged an independent financial advisor to assist in the determination of its reorganized enterprise value. The fair value calculation was based on management’s forecast of expected cash flows from its core assets. Management’s forecast incorporated forward commodity market prices obtained from a third party consulting firm. A discounted cash flow calculation was used to

9

 
NORTHEAST GENERATION HOLDING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

develop the enterprise value of Reorganized NRG, determined in part by calculating the weighted average cost of capital of the Reorganized NRG. The Discounted Cash Flow, (“DCF,”) valuation methodology equates the value of an asset or business to the present value of expected future economic benefits to be generated by that asset or business. The DCF methodology is a “forward looking” approach that discounts expected future economic benefits by a theoretical or observed discount rate. The independent financial advisor prepared a 30-year cash flow forecast using a discount rate of approximately 11%. The resulting reorganization enterprise value as included in the Disclosure Statement ranged from $5.5 billion to $5.7 billion. The independent financial advisor then subtracted NRG Energy’s project level debt and made several other adjustments to reflect the values of assets held for sale, excess cash and collateral requirements to estimate a range of Reorganized NRG equity value of between $2.2 billion and $2.6 billion.

      In constructing the Fresh Start balance sheet upon emergence from bankruptcy, NRG Energy used a reorganization equity value of approximately $2.4 billion, as NRG Energy believed this value to be the best indication of the value of the ownership distributed to the new equity owners. NRG Energy’s Plan of Reorganization provided for the issuance of 100,000,000 shares of NRG Energy common stock to the various creditors resulting in a calculated price per share of $24.04. The reorganization value of approximately $9.1 billion was determined by adding the reorganized equity value of $2.4 billion, $3.7 billion of interest bearing debt and other liabilities of $3.0 billion. The reorganization value represents the fair value of an entity before liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after restructuring. This value is consistent with the voting creditors and Court’s approval of NRG Energy’s Plan of Reorganization.

      The application of SOP 90-7 and push down accounting resulted in the creation of a new reporting entity for the Company. Consequently, the financial statements of the Reorganized Company and the Predecessor Company are separated by a black line to distinguish that the assets, liabilities and equity as well as the results of operations are not comparable between periods. Under the requirements of push down accounting, the Company has adjusted its assets and liabilities to their estimated fair values as of December 5, 2003. The impact of push down accounting resulted in the reduction of member’s equity for the Company in the amount of $10.1 million.

      For financial reporting purposes, close of business on December 5, 2003, represents the date of NRG Energy’s emergence from bankruptcy. As used herein, the following terms refer to the Company and its operations:
 	 	 	
“Predecessor Company”	 	The Company, prior to push down accounting	
 	 	The Company’s operations, January 1, 2001 - December 31, 2001	
 	 	The Company’s operations, January 1, 2002 - December 31, 2002	
 	 	The Company’s operations, January 1, 2003 - December 5, 2003	
“Reorganized Company”	 	The Company, post push down accounting	
 	 	The Company’s operations, December 6, 2003 - December 31, 2003	
      The bankruptcy court in its confirmation order approved NRG Energy’s Plan of Reorganization on November 24, 2003, and subsequently approved the Northeast/ South Central Plan of Reorganization on November 25, 2003. Under the requirements of SOP 90-7, the Fresh Start date is determined to be the confirmation date unless significant uncertainties exist regarding the effectiveness of the bankruptcy order. NRG Energy’s Plan of Reorganization required completion of the Xcel Energy settlement agreement prior to emergence from bankruptcy. Management believes this settlement agreement was a significant contingency and thus delayed the Fresh Start date until the Xcel Energy settlement agreement was finalized on December 5, 2003.

10

 
NORTHEAST GENERATION HOLDING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

 	Investment Impairments	
      Investments accounted for by the equity method are reviewed for impairment in accordance with APB Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock . APB Opinion No. 18 requires that a loss in value of an investment that is other than a temporary decline should be recognized. The Company identifies and measures losses in value of equity investments based upon a comparison of fair value to carrying value.

 	Investment in Affiliate	
      The Company’s investment in Northeast Gen is accounted for under the equity method of accounting. The initial investment was recorded at cost and its carrying value is adjusted to recognize the Company’s share of earnings or losses and dividends.

 	Equity Earnings	
      Earnings are recognized under the equity method of accounting in which the Company recognizes its share of the earnings or losses of the equity affiliate in the periods for which they are reported in the affiliate’s financial statements. Equity earnings are recorded before income taxes of the equity affiliate with the appropriate income taxes recorded as a component of the Company’s income tax provision.

 	Income Taxes	
      The Company has been organized as a limited liability company. Therefore, federal and state income taxes are assessed at the member level. However, a separate company provision for federal and state income taxes has been reflected in the accompanying financial statements (see Note 7 — Income Taxes). As a result of the Company being included in the NRG Energy consolidated tax return and tax payments, federal and state taxes payable amounts resulting from the tax provision are reflected as a contribution by member in the statement of member’s equity and balance sheet.

      Deferred income taxes are recognized for the tax consequences in future years of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts at each year end based on enacted tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. Income tax expense is the tax payable for the period and the change during the period in deferred tax assets and liabilities. A valuation allowance is recorded to reduce deferred tax assets to the amount more likely than not to be realized.

 	Use of Estimates in Financial Statements	
      The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenue and expenses during the reporting period. Actual results may differ from those estimates.

3.	Emergence from Bankruptcy and Fresh Start Reporting	
      In accordance with the requirements of push down accounting, the Company’s fair value of $325.3 million was allocated to the Company’s assets and liabilities based on the individual estimated fair values. A third party was used to complete an independent appraisal of the Company’s tangible assets, intangible assets and contracts.

      The determination of the fair value of the Company’s assets and liabilities was based on a number of estimates and assumptions, which are inherently subject to significant uncertainties and contingencies.

11

 
NORTHEAST GENERATION HOLDING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

      Due to the adoption of push down accounting as of December 5, 2003, the Reorganized Company’s balance sheets, statements of operations and cash flows have not been prepared on a consistent basis with the Predecessor Company’s financial statements and are not comparable in certain respects to the financial statements prior to the application of push down accounting. A black line has been drawn on the accompanying financial statements to separate and distinguish between the Reorganized Company and the Predecessor Company. The effects of the push down accounting adjustments on the Company’s balance sheet as of December 5, 2003, were as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor	 	 	 	Reorganized	
 	 	Company	 	 	 	Company	
 	 	December 5,	 	Push Down	 	December 6,	
 	 	2003	 	Adjustments	 	2003	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
ASSETS	
Investment in affiliate	 	$	301,719	 	 	$	(22,107	)(A)	 	$	279,612	 	
Noncurrent deferred income tax	 	 	33,687	 	 	 	12,029	 (B)	 	 	45,716	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total assets	 	$	335,406	 	 	$	(10,078	)	 	$	325,328	 	

	 	 	 	

	 	 	 	

	 	
 	
LIABILITIES AND MEMBER’S EQUITY	
Member’s equity	 	 	 	 	 	 	 	 	 	 	 	 	
 	Member’s contributions	 	$	374,499	 	 	$	(49,171	)	 	$	325,328	 	
 	Accumulated net loss	 	 	(39,093	)	 	 	39,093	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total member’s equity	 	 	335,406	 	 	 	(10,078	)(C)	 	 	325,328	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total liabilities and member’s equity	 	$	335,406	 	 	$	(10,078	)	 	$	325,328	 	

	 	 	 	

	 	 	 	

	 	

 
 	 	 	
(A)	 	Result of allocating the equity value in conformity with the purchase method of accounting for business combinations. These allocations were based on valuations obtained from independent appraisers.	
 	 	 	
(B)	 	Reflects the adjustment to deferred income tax assets and liabilities due to push down accounting.	
 	 	 	
(C)	 	The changes in member’s equity reflects the fair value adjustment from NRG Energy’s with Fresh Start accounting procedures.	

4.	Derivative Instruments and Hedging Activity	
      On January 1, 2001, the Company adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 137, SFAS No. 138 and SFAS No. 149. SFAS No. 133 requires the Company to record all derivatives on the balance sheet at fair value. Changes in the fair value of nonhedge derivatives will be immediately recognized in earnings. The criteria used to determine if hedge accounting treatment is appropriate are (a) the designation of the hedge to an underlying exposure, (b) whether or not the overall risk is being reduced and (c) if there is high degree of correlation between the value of the derivative instrument and the underlying obligation. Formal documentation of the hedging relationship, the nature of the underlying risk, the risk management objective, and the means by which effectiveness will be assessed is created at the inception of the hedge. Changes in fair values of derivatives accounted for as hedges will either be recognized in earnings as offsets to the changes in fair value of related hedged assets, liabilities and firm commitments or, for forecasted transactions, deferred and recorded as a component of other accumulated comprehensive income, (“OCI,”) until the hedged transactions occur and are recognized in earnings. The ineffective portion of a hedging derivative instrument’s change in fair value will be immediately recognized in earnings. The Company also formally assesses both at inception and at least quarterly thereafter, whether the derivatives that are used in hedging transactions are highly effective in

12

 
NORTHEAST GENERATION HOLDING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

offsetting the changes in either the fair value or cash flows of the hedged item. This assessment includes all components of each derivative’s gain or loss unless otherwise noted. When it is determined that a derivative ceases to be a highly effective hedge, hedge accounting is discontinued.

      SFAS No. 133 applies to the Northeast Gen’s long-term power sales contracts, long-term gas contracts and other energy related commodities financial instruments used to mitigate variability in earnings due to the fluctuations in spot market prices, hedge fuel requirements at generation facilities and protect investments in fuel inventories. At December 31, 2003, Northeast Gen had various commodity contracts extending through April 2004.

 	Accumulated Other Comprehensive Income	
      The following table summarizes the effects of SFAS No. 133 on the Company’s accumulated other comprehensive income balance at December 31, 2003, December 6, 2003 and December 31, 2002, respectively:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the	
 	 	2003 to	 	2003 to	 	Year Ended	
 	 	December 31,	 	December 5,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Energy Commodities Gains (Losses)	 	 	 	 	 	 	 	 	 	 	 	 	
Beginning balance	 	$	—	 	 	$	14,417	 	 	$	53,870	 	
 	Unwound from OCI during period	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Due to unwinding of previously deferred amounts	 	 	—	 	 	 	(14,417	)	 	 	(24,043	)	
 	Mark to market of hedge contracts	 	 	—	 	 	 	—	 	 	 	(15,410	)	

	 	 	 	

	 	 	 	

	 	
Ending balance	 	$	—	 	 	$	—	 	 	$	14,417	 	

	 	 	 	

	 	 	 	

	 	
Gains expected to unwind from OCI during next 12 months	 	$	—	 	 	$	—	 	 	$	14,417	 	
      During the period from January 1, 2003 to December 5, 2003, the Company reclassified gains of $14.4 million from OCI to current-period earnings. During the year ended December 31, 2002, the Company reclassified gains of $24.0 million from OCI to current period earnings. This amount is recorded on the same line in the statement of operations in which the hedged item is recorded. Also during the year ended December 31, 2002, the Company recorded losses in OCI of approximately $15.4 million related to changes in the fair values of derivatives accounted for as hedges. The net balance in OCI relating to SFAS No. 133 at December 31, 2002, was a gain of approximately $14.4 million.

5.	Guarantees	
      In November 2002, the FASB issued FIN 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others . The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor’s fiscal year end. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002. The interpretation addresses the disclosures to be made by guarantor in its interim and annual financial statements about its obligations under guarantees. The interpretation also clarifies the requirements related to the

13

 
NORTHEAST GENERATION HOLDING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

recognition of a liability by a guarantor at the inception of the guarantee for the obligations the guarantor has undertaken in issuing the guarantee.

      In connection with push down accounting, all outstanding guarantees were considered new; accordingly, the Company applied the provisions of FIN 45 to all of those guarantees. Each guarantee was reviewed for the requirement to recognize a liability at inception.

      Northeast Gen and the Company are guarantors under the debt issued by the Company’s parent, NRG Energy. NRG Energy issued $1.25 billion of 8% Second Priority Notes on December 23, 2003, due and payable on December 15, 2013. On January 28, 2004, NRG Energy also issued $475.0 million of Second Priority Notes, under the same terms and indenture as its December 23, 2003 offering.

      NRG Energy’s payment obligations under the notes and all related parity lien obligations are guaranteed on an unconditional basis by each of NRG Energy’s current and future restricted subsidiaries, of which the Company is one. The notes are jointly and severally guaranteed by each of the guarantors. The subsidiary guarantees of the notes are secured, on a second priority basis, equally and ratably with any future parity lien debt, by security interests in all the assets of the guarantors, except certain excluded assets, subject to liens securing parity lien debt and other permitted prior liens.

      The Company’s obligations pursuant to its guarantees of the performance, equity and indebtedness obligations were as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantee/	 	 	 	 	 	 	
 	 	Maximum	 	Nature of	 	Expiration	 	Triggering	
 	 	Exposure	 	Guarantee	 	Date	 	Event	

	 	

	 	

	 	

	
 	 	(In thousands	 	 	 	 	 	 	
 	 	of dollars)	 	 	 	 	 	 	
Project/Subsidiary	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
NRG Energy Second Priority
Notes due 2013	 	$	1,753,000	 	 	Obligations under credit agreement	 	 	2013	 	 	 	Nonperformance	 	

6.	Investments Accounted for by the Equity Method	
      The Company has a 50% equity investment in Northeast Gen which owns electric power generation plants in the northeast region of the United States. NRG Eastern LLC owns the remaining 50% interest in Northeast Gen. The equity method of accounting is applied to such investments in affiliates, which include joint ventures and partnerships because the ownership structure prevents the Company from exercising a controlling influence over operating and financial policies of the projects. Under this method, equity in the pre-tax income or losses of such projects are reflected as equity in earnings of unconsolidated affiliates.

14

 
NORTHEAST GENERATION HOLDING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

      Summarized financial information of the Company’s only unconsolidated affiliate, Northeast Gen, without the impact of income taxes is as follows:

      Results of operations:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Operating revenues	 	$	60,471	 	 	$	730,463	 	 	$	693,869	 	 	$	1,050,688	 	
Costs and expenses	 	 	50,165	 	 	 	985,974	 	 	 	689,984	 	 	 	839,433	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Net income (loss) before taxes	 	$	10,306	 	 	$	(255,511	)	 	$	3,885	 	 	$	211,255	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
      Financial position:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Current assets	 	$	162,283	 	 	$	171,621	 	 	$	317,818	 	
Other assets	 	 	1,064,874	 	 	 	1,067,437	 	 	 	1,375,919	 	

	 	 	 	

	 	 	 	

	 	
 	Total assets	 	$	1,227,157	 	 	$	1,239,058	 	 	$	1,693,737	 	

	 	 	 	

	 	 	 	

	 	
Current liabilities	 	$	84,149	 	 	$	672,345	 	 	$	678,679	 	
Other liabilities	 	 	7,528	 	 	 	7,493	 	 	 	35,495	 	
Member’s equity	 	 	1,135,480	 	 	 	559,220	 	 	 	979,563	 	

	 	 	 	

	 	 	 	

	 	
 	Total liabilities and member’s equity	 	$	1,227,157	 	 	$	1,239,058	 	 	$	1,693,737	 	

	 	 	 	

	 	 	 	

	 	

7.	Income Taxes	
      The Company is included in the consolidated tax return filings as a wholly owned indirect subsidiary of NRG Energy. Reflected in the financial statements and notes below are separate company federal and state tax provisions as if the Company had prepared separate filings. An income tax provision has been established on the accompanying financial statements as of the earliest period presented in order to reflect income taxes as if the Company filed its own tax return. The Company’s parent, NRG Energy, does not have a tax allocation agreement with its subsidiaries and prior to January 1, 2003, income taxes were not recorded or allocated to non tax paying entities or entities such as the Company which are treated as disregarded entities for tax purposes. Because the Company is not a party to a tax sharing agreement, current tax expense (benefit) is recorded as a capital contribution from (distribution to) the Company’s parent. The cumulative effect of recording an income tax provision (benefit) and deferred taxes resulted in recording as of December 31, 2000, a net deferred tax liability of $32.1 million and a reduction to member’s equity of $32.1 million.

15

 
NORTHEAST GENERATION HOLDING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

      The provision (benefit) for income taxes consists of the following:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Current	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Federal	 	$	1,477	 	 	$	5,695	 	 	$	6,047	 	 	$	29,951	 	
 	State	 	 	591	 	 	 	2,278	 	 	 	2,419	 	 	 	11,979	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	2,068	 	 	 	7,973	 	 	 	8,466	 	 	 	41,930	 	
Deferred	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Federal	 	 	114	 	 	 	(44,919	)	 	 	(4,811	)	 	 	2,711	 	
 	State	 	 	46	 	 	 	(17,966	)	 	 	(1,924	)	 	 	1,084	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	160	 	 	 	(62,885	)	 	 	(6,735	)	 	 	3,795	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Total income tax expense (benefit)	 	$	2,228	 	 	$	(54,912	)	 	$	1,731	 	 	$	45,725	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Effective tax rate	 	 	43.2	%	 	 	43.0	%	 	 	89.1	%	 	 	43.3	%	
      The pre-tax income (loss) was as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
U.S. 	 	$	5,148	 	 	$	(127,755	)	 	$	1,942	 	 	$	105,627	 	
      The components of the net deferred income tax (assets) liabilities were:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Investment in project	 	$	—	 	 	$	—	 	 	$	29,198	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total deferred tax liabilities	 	 	—	 	 	 	—	 	 	 	29,198	 	
Deferred tax assets	 	 	 	 	 	 	 	 	 	 	 	 	
 	Investment in project	 	 	45,556	 	 	 	45,716	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total deferred tax assets (before valuation allowance)	 	 	45,556	 	 	 	45,716	 	 	 	—	 	
Valuation allowance	 	 	—	 	 	 	—	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
Net deferred tax assets	 	 	45,556	 	 	 	45,716	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
Net deferred tax (assets) liabilities	 	$	(45,556	)	 	$	(45,716	)	 	$	29,198	 	

	 	 	 	

	 	 	 	

	 	
16

 
NORTHEAST GENERATION HOLDING LLC

NOTES TO FINANCIAL STATEMENTS — (Continued)

      The net deferred tax (assets) liabilities consists of:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Current deferred tax (assets) liabilities	 	$	—	 	 	$	—	 	 	$	—	 	
Noncurrent deferred tax (assets) liabilities	 	 	(45,556	)	 	 	(45,716	)	 	 	29,198	 	

	 	 	 	

	 	 	 	

	 	
Net deferred tax (assets) liabilities	 	$	(45,556	)	 	$	(45,716	)	 	$	29,198	 	

	 	 	 	

	 	 	 	

	 	
      The effective income tax rates of continuing operations differ from the statutory federal income tax rate of 35% as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	 	 	
 	 	Company	 	 	 	Predecessor Company	

	 	 	 	

	
 	 	For the	 	 	 	For the	 	 	
 	 	Period from	 	 	 	Period from	 	 	 	 	
 	 	December 6,	 	 	 	January 1,	 	 	 	For the Years Ended	
 	 	2003 to	 	 	 	2003 to	 	 	 	December 31,	
 	 	December 31,	 	 	 	December	 	 	 	

	
 	 	2003	 	 	 	5, 2003	 	 	 	2002	 	 	 	2001	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	
 	 	 	
 	 	(In thousands of dollars)	
Income (loss) before taxes	 	$	5,148	 	 	 	 	 	 	$	(127,755	)	 	 	 	 	 	$	1,942	 	 	 	 	 	 	$	105,627	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	
Tax at 35%	 	 	1,802	 	 	 	35.0	%	 	 	(44,715	)	 	 	35.0	%	 	 	680	 	 	 	35.0	%	 	 	36,969	 	 	 	35.0	%	
State taxes (net of federal benefit)	 	 	414	 	 	 	8.0	%	 	 	(10,197	)	 	 	8.0	%	 	 	322	 	 	 	16.6	%	 	 	8,491	 	 	 	8.0	%	
Other	 	 	12	 	 	 	0.2	%	 	 	—	 	 	 	—	%	 	 	729	 	 	 	37.5	%	 	 	265	 	 	 	0.3	%	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	
Income tax expense (benefit)	 	$	2,228	 	 	 	43.2	%	 	$	(54,912	)	 	 	43.0	%	 	$	1,731	 	 	 	89.1	%	 	$	45,725	 	 	 	43.3	%	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	

8.	Commitments and Contingencies	
      In the normal course of business, the Company is subject to various claims and litigation. Management of the Company expects that these various litigation items will not have a material adverse effect on the results of operations or financial position of the Company.

17

 

EXHIBIT 99.9

NRG INTERNATIONAL LLC

Consolidated Financial Statements
At December 31, 2003, December 6, 2003 and December 31, 2002, and for the Period
from December 6, 2003 to December 31, 2003, the Period from January 1, 2003 to
December 5, 2003 and for the Years Ended December 31, 2002 and 2001

 

NRG INTERNATIONAL LLC

INDEX
 	 	 	 	 	 	
 	 	Page(s)	

	
Reports of Independent Auditors	 	 	1-2	 	
Consolidated Financial Statements	 	 	 	 	
 	Consolidated Balance Sheets at December 31, 2003, December 6, 2003 and December 31, 2002	 	 	3	 	
 	Consolidated Statements of Operations for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001	 	 	4	 	
 	Consolidated Statements of Member’s Equity for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001	 	 	5	 	
 	Consolidated Statements of Cash Flows for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001	 	 	6	 	
Notes to Consolidated Financial Statements	 	 	7-45	 	
Report of Independent Auditors of Financial Statement Schedule	 	 	46-47	 	
Financial Statement Schedule	 	 	48	 	

 

REPORT OF INDEPENDENT AUDITORS

To the Member of NRG International LLC

      In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, of member’s equity, and of cash flows present fairly, in all material respects, the financial position of NRG International LLC and its subsidiaries (“Predecessor Company”) at December 31, 2002, and the results of their operations and their cash flows for the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      As discussed in Note 1 to the consolidated financial statements, on May 14, 2003, NRG Energy, Inc. and certain of its subsidiaries filed a petition with the United States Bankruptcy Court for the Southern District of New York for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. NRG Energy, Inc.’s Plan of Reorganization was substantially consummated on December 5, 2003, and Reorganized NRG emerged from bankruptcy. The impact of NRG Energy, Inc.’s emergence from bankruptcy and fresh start accounting was applied to the Company on December 5, 2003, under push down accounting methodology.

      As discussed in Notes 2 and 6 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”, on January 1, 2002. As discussed in Note 11 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations”, as of January 1, 2003. As discussed in Note 12 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as of January 1, 2001.

      As discussed in Note 4 to the consolidated financial statements, during the second quarter of 2004 Hsin Yu met the criteria for discontinued operations. Accordingly, all periods presented have been restated to present Hsin Yu as a discontinued operation.
 	 	
 	/s/ PRICEWATERHOUSECOOPERS LLP	

	
 	PricewaterhouseCoopers LLP	
October 29, 2004

1

 

REPORT OF INDEPENDENT AUDITORS

To the Member of NRG International LLC

      In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of member’s equity, and of cash flows present fairly, in all material respects, the financial position of NRG International LLC and its subsidiaries (“Reorganized Company”) at December 31, 2003 and December 6, 2003, and the results of their operations and their cash flows for the period from December 6, 2003 to December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      As discussed in Note 1 to the consolidated financial statements, on May 14, 2003, NRG Energy, Inc. and certain of its subsidiaries filed a petition with the United States Bankruptcy Court for the Southern District of New York for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. NRG Energy, Inc.’s Plan of Reorganization was substantially consummated on December 5, 2003, and Reorganized NRG emerged from bankruptcy. The impact of NRG Energy, Inc.’s emergence from bankruptcy and fresh start accounting was applied to the Company on December 5, 2003, under push down accounting methodology.

      As discussed in Notes 2 and 6 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”, on January 1, 2002. As discussed in Note 11 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations”, as of January 1, 2003. As discussed in Note 12 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as of January 1, 2001.

      As discussed in Note 4 to the consolidated financial statements, during the second quarter of 2004 Hsin Yu met the criteria for discontinued operations. Accordingly, all periods presented have been restated to present Hsin Yu as a discontinued operation.
 	 	
 	/s/ PRICEWATERHOUSECOOPERS LLP	

	
 	PricewaterhouseCoopers LLP	
October 29, 2004

2

 

NRG INTERNATIONAL LLC

CONSOLIDATED BALANCE SHEETS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
ASSETS	
Current assets	 	 	 	 	 	 	 	 	 	 	 	 	
 	Cash and cash equivalents	 	$	127,020	 	 	$	125,914	 	 	$	192,862	 	
 	Restricted cash	 	 	45,874	 	 	 	44,802	 	 	 	17,214	 	
 	Accounts receivable, less allowance for doubtful accounts of $0, $0 and $368, respectively	 	 	40,309	 	 	 	39,072	 	 	 	35,515	 	
 	Accounts receivable — affiliates	 	 	5,404	 	 	 	5,893	 	 	 	36,730	 	
 	Current portion of notes receivable	 	 	64,720	 	 	 	64,720	 	 	 	49,288	 	
 	Current portion of notes receivable — affiliates	 	 	—	 	 	 	—	 	 	 	2,442	 	
 	Inventory	 	 	17,900	 	 	 	16,178	 	 	 	10,659	 	
 	Prepayments and other current assets	 	 	3,790	 	 	 	4,607	 	 	 	5,458	 	
 	Current deferred income tax	 	 	754	 	 	 	—	 	 	 	—	 	
 	Current assets — discontinued operations	 	 	12,615	 	 	 	13,148	 	 	 	113,800	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total current assets	 	 	318,386	 	 	 	314,334	 	 	 	463,968	 	
Property, plant and equipment, net of accumulated depreciation of $1,467, $0 and $33,683 respectively	 	 	458,224	 	 	 	447,457	 	 	 	320,748	 	
Equity investments in affiliates	 	 	332,617	 	 	 	326,798	 	 	 	309,748	 	
Notes receivable, less current portion	 	 	444,052	 	 	 	427,648	 	 	 	380,853	 	
Notes receivable — affiliate, less current portion	 	 	111,913	 	 	 	107,412	 	 	 	133,066	 	
Derivative instruments valuation	 	 	59,907	 	 	 	66,442	 	 	 	48,460	 	
Other assets	 	 	4,450	 	 	 	51	 	 	 	15	 	
Noncurrent assets — discontinued operations	 	 	47,476	 	 	 	47,905	 	 	 	477,759	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total assets	 	$	1,777,025	 	 	$	1,738,047	 	 	$	2,134,617	 	

	 	 	 	

	 	 	 	

	 	
 	
LIABILITIES AND MEMBER’S EQUITY	
Current liabilities	 	 	 	 	 	 	 	 	 	 	 	 	
 	Current portion of long-term debt	 	$	75,944	 	 	$	61,473	 	 	$	26,509	 	
 	Notes payable — affiliate	 	 	10,664	 	 	 	10,664	 	 	 	35,051	 	
 	Accounts payable	 	 	30,271	 	 	 	28,898	 	 	 	20,416	 	
 	Accounts payable — affiliate	 	 	2,976	 	 	 	15,385	 	 	 	19,307	 	
 	Accrued income tax	 	 	18,673	 	 	 	17,023	 	 	 	11,919	 	
 	Accrued liabilities	 	 	4,471	 	 	 	10,154	 	 	 	1,501	 	
 	Other current liabilities	 	 	1,839	 	 	 	2,818	 	 	 	588	 	
 	Current liabilities — discontinued operations	 	 	62,993	 	 	 	62,415	 	 	 	532,516	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total current liabilities	 	 	207,831	 	 	 	208,830	 	 	 	647,807	 	
Other liabilities	 	 	 	 	 	 	 	 	 	 	 	 	
 	Long-term debt	 	 	266,526	 	 	 	256,886	 	 	 	307,420	 	
 	Long-term debt — affiliates	 	 	198,300	 	 	 	196,259	 	 	 	98,276	 	
 	Deferred income taxes	 	 	165,883	 	 	 	161,908	 	 	 	110,809	 	
 	Postretirement and other benefit obligations	 	 	14,016	 	 	 	14,739	 	 	 	11,936	 	
 	Derivative instruments valuation	 	 	112,047	 	 	 	108,801	 	 	 	90,536	 	
 	Other long-term obligations	 	 	14,959	 	 	 	14,465	 	 	 	14,185	 	
 	Noncurrent liabilities — discontinued operations	 	 	3,729	 	 	 	4,902	 	 	 	203,039	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total liabilities	 	 	983,291	 	 	 	966,790	 	 	 	1,484,008	 	

	 	 	 	

	 	 	 	

	 	
Commitments and contingencies	 	 	 	 	 	 	 	 	 	 	 	 	
Member’s equity	 	 	793,734	 	 	 	771,257	 	 	 	650,609	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total liabilities and member’s equity	 	$	1,777,025	 	 	$	1,738,047	 	 	$	2,134,617	 	

	 	 	 	

	 	 	 	

	 	
The accompanying notes are an integral part of these consolidated financial statements.

3

 

NRG INTERNATIONAL LLC

CONSOLIDATED STATEMENTS OF OPERATIONS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Revenues	 	$	23,358	 	 	$	271,665	 	 	$	279,750	 	 	$	285,122	 	
Operating costs	 	 	18,754	 	 	 	212,917	 	 	 	236,378	 	 	 	235,018	 	
Depreciation and amortization	 	 	1,475	 	 	 	15,847	 	 	 	15,000	 	 	 	14,774	 	
General and administrative expenses	 	 	993	 	 	 	9,278	 	 	 	9,824	 	 	 	14,401	 	
Restructuring and impairment charges	 	 	—	 	 	 	3,929	 	 	 	53,501	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	Income (loss) from operations	 	 	2,136	 	 	 	29,694	 	 	 	(34,953	)	 	 	20,929	 	
Minority interest in losses of consolidated subsidiaries	 	 	—	 	 	 	—	 	 	 	(470	)	 	 	—	 	
Equity in earnings of unconsolidated affiliates	 	 	1,707	 	 	 	61,900	 	 	 	49,297	 	 	 	56,922	 	
Write downs and losses on sales of equity method investments	 	 	—	 	 	 	(138,371	)	 	 	(139,146	)	 	 	—	 	
Other income, net	 	 	1,148	 	 	 	443	 	 	 	8,179	 	 	 	5,003	 	
Interest expense	 	 	(709	)	 	 	(7,021	)	 	 	(7,239	)	 	 	(6,760	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	Income (loss) from continuing operations before income taxes	 	 	4,282	 	 	 	(53,355	)	 	 	(124,332	)	 	 	76,094	 	
Income tax expense	 	 	796	 	 	 	11,363	 	 	 	13,743	 	 	 	16,040	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	Income (loss) from continuing operations	 	 	3,486	 	 	 	(64,718	)	 	 	(138,075	)	 	 	60,054	 	
Income (loss) on discontinued operations, net of income taxes	 	 	(222	)	 	 	169,183	 	 	 	(553,008	)	 	 	40,276	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	Net income (loss)	 	$	3,264	 	 	$	104,465	 	 	$	(691,083	)	 	$	100,330	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
The accompanying notes are an integral part of these consolidated financial statements.

4

 

NRG INTERNATIONAL LLC

CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Accumulated	 	 	
 	 	 	 	 	 	 	 	Other	 	 	
 	 	Member	 	Member	 	Accumulated	 	Comprehensive	 	Total	

	 	Contributions/	 	Net Income	 	Income	 	Member’s	
 	 	Units	 	Amount	 	Distributions	 	(Loss)	 	(Loss)	 	Equity	

	 	

	 	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Balances at December 31, 2000 (Predecessor Company)	 	 	1,000	 	 	$	1	 	 	$	789,659	 	 	$	211,022	 	 	$	(160,124	)	 	$	840,558	 	
Net income	 	 	—	 	 	 	—	 	 	 	—	 	 	 	100,330	 	 	 	—	 	 	 	100,330	 	
Foreign currency translation adjustments and other	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(46,290	)	 	 	(46,290	)	
Impact of SFAS No. 133 for the year ending December 31, 2001, net of taxes of $25.3 million	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	29,504	 	 	 	29,504	 	

	 	
Comprehensive income	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	83,544	 	
Contribution from member	 	 	 	 	 	 	 	 	 	 	348,059	 	 	 	 	 	 	 	 	 	 	 	348,059	 	
Distributions to member	 	 	—	 	 	 	—	 	 	 	(165,891	)	 	 	—	 	 	 	—	 	 	 	(165,891	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Balances at December 31, 2001 (Predecessor Company)	 	 	1,000	 	 	 	1	 	 	 	971,827	 	 	 	311,352	 	 	 	(176,910	)	 	 	1,106,270	 	
Net loss	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(691,083	)	 	 	—	 	 	 	(691,083	)	
Foreign currency translation adjustments and other	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	97,912	 	 	 	97,912	 	
Impact of SFAS No. 133 for the year ending December 31, 2002, net of taxes of $8.6 million	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	23,648	 	 	 	23,648	 	

	 	
Comprehensive loss	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(569,523	)	
Contribution from member	 	 	—	 	 	 	—	 	 	 	113,862	 	 	 	—	 	 	 	—	 	 	 	113,862	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Balances at December 31, 2002 (Predecessor Company)	 	 	1,000	 	 	 	1	 	 	 	1,085,689	 	 	 	(379,731	)	 	 	(55,350	)	 	 	650,609	 	
Net Profit(loss)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	104,465	 	 	 	—	 	 	 	104,465	 	
Foreign currency translation adjustments and other	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	82,069	 	 	 	82,069	 	
Impact of SFAS No. 133 for the period ending December 5, 2003, net of taxes of $22.4 million	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	3,141	 	 	 	3,141	 	

	 	
Comprehensive income	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	189,675	 	
Distributions to member	 	 	—	 	 	 	—	 	 	 	(112,000	)	 	 	—	 	 	 	—	 	 	 	(112,000	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Balances at December 5, 2003 (Predecessor Company)	 	 	1,000	 	 	 	1	 	 	 	973,689	 	 	 	(275,266	)	 	 	29,860	 	 	 	728,284	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Push down accounting adjustment	 	 	—	 	 	 	—	 	 	 	(202,433	)	 	 	275,266	 	 	 	(29,860	)	 	 	42,973	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Balances at December 6, 2003 (Reorganized Company)	 	 	1,000	 	 	 	1	 	 	 	771,256	 	 	 	—	 	 	 	—	 	 	 	771,257	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Net income	 	 	—	 	 	 	—	 	 	 	—	 	 	 	3,264	 	 	 	—	 	 	 	3,264	 	
Foreign currency translation adjustments and other	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	21,364	 	 	 	21,364	 	
Impact of SFAS No. 133 for the period ending December 31, 2003, net of taxes of $1 million	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(2,151	)	 	 	(2,151	)	

	 	
Comprehensive income	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	22,477	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Balances at December 31, 2003 (Reorganized Company)	 	 	1,000	 	 	$	1	 	 	$	771,256	 	 	$	3,264	 	 	$	19,213	 	 	$	793,734	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
The accompanying notes are an integral part of these consolidated financial statements.

5

 

NRG INTERNATIONAL LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Cash flows from operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	$	3,264	 	 	$	104,465	 	 	$	(691,083	)	 	$	100,330	 	
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Distributions in excess (less than) equity earnings of nonconsolidated affiliates	 	 	5,549	 	 	 	(53,580	)	 	 	(25,893	)	 	 	(45,225	)	
 	Write downs and losses on sales of equity method investments	 	 	—	 	 	 	138,371	 	 	 	139,146	 	 	 	—	 	
 	Restructuring and impairment charges	 	 	—	 	 	 	3,929	 	 	 	620,193	 	 	 	—	 	
 	Depreciation and amortization	 	 	2,011	 	 	 	23,742	 	 	 	51,051	 	 	 	44,457	 	
 	Bad debt expense	 	 	—	 	 	 	(14,255	)	 	 	—	 	 	 	9,617	 	
 	Unrealized (gains) losses on derivatives	 	 	391	 	 	 	(122,937	)	 	 	17,368	 	 	 	(53,170	)	
 	Unrealized exchange (gains) losses	 	 	(310	)	 	 	(2,663	)	 	 	2,290	 	 	 	(24	)	
 	Deferred income taxes	 	 	(2,374	)	 	 	39,790	 	 	 	7,287	 	 	 	35,311	 	
 	Minority interest	 	 	(17	)	 	 	(1,793	)	 	 	(21,655	)	 	 	(1,041	)	
 	Gain on sale of discontinued operations	 	 	—	 	 	 	(164,126	)	 	 	(18,690	)	 	 	—	 	
 	Deferred income	 	 	—	 	 	 	—	 	 	 	13,890	 	 	 	2,551	 	
 	Amortization of out-of-market power contracts	 	 	3,048	 	 	 	6,543	 	 	 	1,889	 	 	 	(6,247	)	
 	Changes in assets and liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Accounts receivable	 	 	2,265	 	 	 	(48,863	)	 	 	10,220	 	 	 	(39,838	)	
 	 	Inventory	 	 	(1,186	)	 	 	(2,307	)	 	 	(957	)	 	 	2,782	 	
 	 	Prepayments and other current assets	 	 	(436	)	 	 	(3,519	)	 	 	15,284	 	 	 	(19,653	)	
 	 	Accounts payable	 	 	(1,265	)	 	 	(6,410	)	 	 	(28,537	)	 	 	(10,863	)	
 	 	Accrued interest	 	 	(4,554	)	 	 	3,157	 	 	 	1,439	 	 	 	(724	)	
 	 	Accrued income taxes	 	 	945	 	 	 	(2,733	)	 	 	8,222	 	 	 	1,079	 	
 	 	Accrued liabilities	 	 	(850	)	 	 	8,080	 	 	 	(2,009	)	 	 	(2,461	)	
 	 	Changes in other assets and liabilities	 	 	(1,307	)	 	 	15,367	 	 	 	(8,242	)	 	 	1,609	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	Net cash provided by (used in) operating activities	 	 	5,174	 	 	 	(79,742	)	 	 	91,213	 	 	 	18,490	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Cash flows from investing activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Investments in affiliates	 	 	(3,475	)	 	 	(44,728	)	 	 	(91,859	)	 	 	(63,410	)	
Capital expenditures	 	 	(1,080	)	 	 	(69,487	)	 	 	(61,421	)	 	 	(26,320	)	
Acquisitions, net of liabilities assumed	 	 	—	 	 	 	—	 	 	 	(411	)	 	 	(96,764	)	
Proceeds from sale of investments	 	 	(10	)	 	 	35,117	 	 	 	32,916	 	 	 	(11,514	)	
Decrease in note receivable	 	 	—	 	 	 	64,901	 	 	 	—	 	 	 	—	 	
Proceeds from sale of discontinued operations	 	 	263	 	 	 	164,078	 	 	 	27,259	 	 	 	1,026	 	
(Increase) decrease in restricted cash	 	 	—	 	 	 	(18,253	)	 	 	(18,274	)	 	 	(333	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	Net cash (used in) provided by investing activities	 	 	(4,302	)	 	 	131,628	 	 	 	(111,790	)	 	 	(197,315	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Cash flows from financing activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Proceeds from issuance of debt	 	 	—	 	 	 	62,300	 	 	 	7,034	 	 	 	61,306	 	
Contribution from member	 	 	—	 	 	 	—	 	 	 	113,862	 	 	 	348,059	 	
Principal payments on long-term debt	 	 	(2,370	)	 	 	(42,013	)	 	 	(42,880	)	 	 	(6,163	)	
Distributions to member	 	 	—	 	 	 	(112,000	)	 	 	—	 	 	 	(165,891	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	Net cash (used in) provided by financing activities	 	 	(2,370	)	 	 	(91,713	)	 	 	78,016	 	 	 	237,311	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Effect of exchange rate changes on cash and cash equivalents	 	 	2,323	 	 	 	(53,767	)	 	 	20,166	 	 	 	(3,119	)	
Change in cash from discontinued operations	 	 	281	 	 	 	26,646	 	 	 	50,939	 	 	 	(21,384	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	Net change in cash and cash equivalents	 	 	1,106	 	 	 	(66,948	)	 	 	128,544	 	 	 	33,983	 	
Cash and cash equivalents	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Beginning of period	 	 	125,914	 	 	 	192,862	 	 	 	64,318	 	 	 	30,335	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
End of period	 	$	127,020	 	 	$	125,914	 	 	$	192,862	 	 	$	64,318	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
The accompanying notes are an integral part of these consolidated financial statements.

6

 

NRG INTERNATIONAL LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.	Organization	
      NRG International LLC (the “Company”), a Delaware company incorporated on October 12, 1992, and converted to a limited liability company in November 2002, is a directly held, wholly owned subsidiary of NRG Energy, Inc. (“NRG Energy”).

      The Company was formed for the purpose of financing, acquiring, owning, operating and maintaining, through its subsidiaries and affiliates, the power generation facilities owned by Flinders Power in Australia, and Saale Energie GmbH in Germany. Flinders is a 760 MW power station and coal mine which sells electricity into the South Australian market. Saale Energie GmbH owns a 400 MW coal powered power station located in Halle Germany and sells output to Vattenfall Europe A.G. (“VEAG”) under a power purchase agreement. In addition, the Company holds various investments in projects accounted for under the equity method, and holds operations classified as discontinued operations. See Notes 10 and 4, respectively.

      At December 31, 2003, the Company owned total interests in eight power projects in six countries having an aggregate generation capacity of approximately 2,500 MW in various international markets, including Australia, Europe and Latin America.

 	Recent Developments	
      On May 14, 2003, NRG Energy and 25 of its direct and indirect wholly owned subsidiaries commenced voluntary petitions under Chapter 11 of the bankruptcy code in the United States Bankruptcy Court for the Southern District of New York. During the bankruptcy proceedings, NRG Energy continued to conduct business and manage the companies as debtors in possession pursuant to sections 1107(a) and 1108 of the bankruptcy code. The Company was not part of these Chapter 11 cases or any of the subsequent bankruptcy filings. On November 24, 2003, the bankruptcy court entered an order confirming NRG Energy’s Plan of Reorganization and the plan became effective on December 5, 2003. In connection with NRG Energy’s emergence from bankruptcy, NRG Energy adopted fresh start reporting in accordance with AICPA Statement of Position 90-7,  Financial Reporting by Entities in Reorganization Under the Bankruptcy Code  (“SOP 90-7”) on December 5, 2003. NRG Energy’s fresh start reporting was applied to the Company on a push down accounting basis with the financial statement impact recorded as an adjustment to the December 5, 2003, member’s equity in the amount of $28.0 million.

 	NRG Energy’s Plan of Reorganization	
      NRG Energy’s Plan of Reorganization was the result of several months of intense negotiations among NRG Energy, Xcel Energy (“Xcel Energy”) and the two principal committees representing NRG Energy creditor groups, referred to as the Global Steering Committee and the Noteholder Committee. A principal component of NRG Energy’s Plan of Reorganization was a settlement with Xcel Energy in which Xcel Energy agreed to make a contribution consisting of cash (and, under certain circumstances, its stock) in the aggregate amount of up to $640 million to be paid in three separate installments following the effective date of NRG Energy’s Plan of Reorganization. The Xcel Energy settlement agreement resolves any and all claims existing between Xcel Energy and NRG Energy and/or its creditors and, in exchange for the Xcel Energy contribution, Xcel Energy is receiving a complete release of claims from NRG Energy and its creditors, except for a limited number of creditors who have preserved their claims as set forth in the confirmation order entered on November 24, 2003.

2.	Summary of Significant Accounting Policies	

 	Principles of Consolidation	
      The consolidated financial statements include the accounts of the Company and its subsidiaries. All significant intercompany transactions and balances have been eliminated in consolidation. Accounting policies

7

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

for all of the Company’s operations are in accordance with the accounting principles generally accepted in the United States of America.

 	NRG Energy Fresh Start Reporting/ Push Down Accounting	
      In accordance with SOP 90-7, certain companies qualify for fresh start (“Fresh Start”) reporting in connection with their emergence from bankruptcy. Fresh Start reporting is appropriate on the emergence from Chapter 11 if the reorganization value of the assets of the emerging entity immediately before the date of confirmation is less than the total of all post-petition liabilities and allowed claims, and if the holders of existing voting shares immediately before confirmation receive less than 50% of the voting shares of the emerging entity. NRG Energy met these requirements and adopted Fresh Start reporting and applied push down accounting to its various subsidiary operations including the Company. Under push down accounting, the Company’s equity fair value was allocated to the Company’s assets and liabilities based on their estimated fair values as of December 5, 2003, as further described in Note 3.

      Under the requirements of Fresh Start, NRG Energy adjusted its assets and liabilities, other than deferred income taxes, to their estimated fair values as of December 5, 2003. As a result of marking the assets and liabilities to their estimated fair values, NRG Energy determined that there was a negative reorganization value that was reallocated back to the tangible and intangible assets. Deferred taxes were determined in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 109,  Accounting for Income Taxes.  The net effect of all Fresh Start adjustments resulted in a gain of $3.9 billion, which is reflected in NRG Energy’s Predecessor Company results for the period from January 1, 2003 to December 5, 2003. The application of the Fresh Start provisions of SOP 90-7 created a new reporting entity having no retained earnings or accumulated deficit.

      As part of the bankruptcy process, NRG Energy engaged an independent financial advisor to assist in the determination of its reorganized enterprise value. The fair value calculation was based on management’s forecast of expected cash flows from its core assets. Management’s forecast incorporated forward commodity market prices obtained from a third party consulting firm. A discounted cash flow calculation was used to develop the enterprise value of Reorganized NRG, determined in part by calculating the weighted average cost of capital of the Reorganized NRG. The Discounted Cash Flow, (“DCF”) valuation methodology equates the value of an asset or business to the present value of expected future economic benefits to be generated by that asset or business. The DCF methodology is a “forward looking” approach that discounts expected future economic benefits by a theoretical or observed discount rate. The independent financial advisor prepared a 30-year cash flow forecast using a discount rate of approximately 11%. The resulting reorganization enterprise value as included in the Disclosure Statement ranged from $5.5 billion to $5.7 billion. The independent financial advisor then subtracted NRG Energy’s project level debt and made several other adjustments to reflect the values of assets held for sale, excess cash and collateral requirements to estimate a range of Reorganized NRG equity value of between $2.2 billion and $2.6 billion.

      In constructing the Fresh Start balance sheet upon emergence from bankruptcy, NRG Energy used a reorganization equity value of approximately $2.4 billion, as NRG Energy believed this value to be the best indication of the value of the ownership distributed to the new equity owners. NRG Energy’s Plan of Reorganization provided for the issuance of 100,000,000 shares of NRG Energy common stock to the various creditors resulting in a calculated price per share of $24.04. The reorganization value of approximately $9.1 billion was determined by adding the reorganized equity value of $2.4 billion, $3.7 billion of interest bearing debt and other liabilities of $3.0 billion. The reorganization value represents the fair value of an entity before liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after restructuring. This value is consistent with the voting creditors and Court’s approval of NRG Energy’s Plan of Reorganization.

8

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The application of SOP 90-7 and push down accounting resulted in the creation of a new reporting entity for the Company. Consequently, the financial statements of the Reorganized Company and the Predecessor Company are separated by a black line to distinguish that the assets, liabilities and member’s equity as well as the results of operations are not comparable between periods. Under the requirements of push down accounting, the Company has adjusted its assets and liabilities to their estimated fair values as of December 5, 2003. The impact of push down accounting resulted in an increase of member’s equity for the Company in the amount of $28.0 million.

      For financial reporting purposes, close of business on December 5, 2003, represents the date of NRG Energy’s emergence from bankruptcy. As used herein, the following terms refer to the Company and its operations:
 	 	 	
 	“Predecessor Company”	The Company, prior to push down accounting	
The Company’s operations, January 1, 2001 — December 31, 2001
The Company’s operations, January 1, 2002 — December 31, 2002
The Company’s operations, January 1, 2003 — December 5, 2003
 	 	 	
 	“Reorganized Company” 	The Company, post push down accounting	
The Company’s operations, December 6, 2003 — December 31, 2003

      The bankruptcy court in its confirmation order approved NRG Energy’s Plan of Reorganization on November 24, 2003. Under the requirements of SOP 90-7, the Fresh Start date is determined to be the confirmation date unless significant uncertainties exist regarding the effectiveness of the bankruptcy order. The Plan of Reorganization required completion of the Xcel Energy settlement agreement prior to emergence from bankruptcy. Management believes this settlement agreement was a significant contingency and thus delayed the Fresh Start date until the Xcel Energy settlement agreement was finalized on December 5, 2003.

 	Cash and Cash Equivalents	
      Cash and cash equivalents include highly liquid investments with an original maturity of three months or less at the time of purchase.

 	Restricted Cash	
      Restricted cash consists primarily of funds held based upon negotiated amounts to satisfy the principal and interest requirements of certain debt agreements and funds held within the Company’s subsidiaries that are restricted in their use.

 	Inventory	
      Inventory consists of fuel oil, spare parts and coal and is valued at the lower of weighted average cost or market.

 	Property, Plant and Equipment	
      The Company’s property, plant and equipment is stated at cost; however, impairment adjustments are recorded whenever events or changes in circumstances indicate carrying values may not be recoverable. At December 5, 2003, the Company recorded adjustments to the property, plant and equipment to reflect such items at fair value in accordance with the application of push down accounting. A new cost basis was established with these adjustments. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance that do not improve or extend the life of the respective asset, are charged to expense as incurred. Depreciation is calculated using the straight-line method over the estimated useful

9

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

lives of the assets. The assets and related accumulated depreciation amounts are adjusted for asset retirements and disposals, with the resulting gain or loss included in operations.

 	Asset Impairment	
      Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate carrying values may not be recoverable. Such reviews are performed in accordance with SFAS No. 144,  Accounting for the Impairment or Disposal of Long-lived Assets.  An impairment loss is recognized if the total future estimated undiscounted cash flows expected from an asset are less than its carrying value. An impairment charge is measured by the difference between an asset’s carrying amount and fair value. Fair values are determined by a variety of valuation methods, including appraisals, sales prices of similar assets and present value techniques.

      Investments accounted for by the equity method are reviewed for impairment in accordance with APB Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock.  APB Opinion No. 18 requires that a loss in value of an investment that is other than a temporary decline should be recognized. The Company identifies and measures losses in value of equity investments based upon a comparison of fair value to carrying value.

 	Discontinued Operations	
      Long-lived assets are classified as discontinued operations when all of the required criteria specified in SFAS No. 144 are met. These criteria include, among others, existence of a qualified plan to dispose of an asset, an assessment that completion of a sale within one year is probable and approval of the appropriate level of management and board of directors. Discontinued operations are reported at the lower of the asset’s carrying amount or fair value less cost to sell.

 	Capitalized Interest	
      Interest incurred on funds borrowed to finance projects expected to require more than three months to complete is capitalized. Capitalization of interest is discontinued when the asset under construction is ready for its intended use or when a project is terminated or construction ceased. Capitalized interest was approximately $0.7 million and $5.4 million for the period from December 6, 2003 to December 31, 2003 and for the period from January 1, 2003 to December 5, 2003, respectively. For the years ended December 31, 2002 and 2001, the Company capitalized interest of $1.2 million and $0, respectively.

 	Capitalized Project Costs	
      Development costs and capitalized project costs include third party professional services, permits, and other costs that are incurred incidental to a particular project. Such costs are expensed as incurred until an acquisition agreement or letter of intent is signed, and the Company’s Board of Directors has approved the project. Additional costs incurred after this point are capitalized. When a project begins operation, previously capitalized project costs are reclassified to equity investments in affiliates or property, plant and equipment and amortized on a straight-line basis over the lesser of the life of the project’s related assets or revenue contract period. Capitalized costs are charged to expense if a project is abandoned or management otherwise determines the costs to be unrecoverable.

 	Fair Value of Financial Instruments	
      The carrying amount of cash and cash equivalents, receivables, accounts payables, and accrued liabilities approximate fair value because of the short maturity of these instruments. The carrying amounts of notes receivables is based on expected future cash flows discounted at market interest rates. The fair value of long-

10

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

term debt is estimated based on a present value method using current interest rates for similar instruments with equivalent credit quality.

 	Income Taxes	
      The Company has been organized as a limited liability company. Therefore, federal and state income taxes are assessed at the member level while foreign taxes are assessed on a separate company country-by-country basis. However, a provision for separate company federal and state income taxes has been included with the foreign taxes and reflected in the accompanying consolidated financial statements (see Note 16 — Income Taxes). As a result of the Company being included in the NRG Energy consolidated tax return and tax payments, federal and state taxes payable amounts resulting from the tax provision are reflected as a contribution by members in the consolidated statement of members’ equity and consolidated balance sheet.

      Deferred income taxes are recognized for the tax consequences in future years of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts at each year end based on enacted tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. Income tax expense is the tax payable for the period and the change during the period in deferred tax assets and liabilities. A valuation allowance is recorded to reduce deferred tax assets to the amount more likely than not to be realized.

      As of December 31, 2003, NRG Energy’s management intends to indefinitely reinvest any earnings from its foreign operations. Accordingly, U.S. income taxes and foreign withholding taxes would not be provided on the earnings of foreign subsidiaries. However, as of December 31, 2003, the Company had cumulative losses from its foreign operations.

 	Equity Investment in Affiliates	
      The Company’s investment in affiliates is accounted for under the equity method of accounting where the Company owns 50% or less of the equity interests. The initial investments were recorded at cost and their carrying values are adjusted to recognize the Company’s share of earnings or losses and dividends. The equity investment values were adjusted on December 5, 2003, in connection with push down accounting.

 	Equity Earnings	
      Earnings are recognized under the equity method of accounting in which the Company recognizes its share of the earnings or losses of the equity affiliates in the periods for which they are reported in the affiliate’s financial statements.

 	Revenue Recognition	
      The Company is primarily an electric generation company, operating a portfolio of majority-owned electric generating plants and certain plants in which ownership interest is 50% or less and which are accounted for under the equity method. Electrical energy revenue is recognized upon delivery to the customer. Capacity and ancillary revenue is recognized when contractually earned.

      The Company provides contract operations and maintenance services to certain nonconsolidated affiliates. Revenue is recognized as contract services are performed. The Company recognizes other income for interest income on loans to nonconsolidated affiliates, as the interest is earned and realizable, either through monthly cash payments and/or annual dividends.

11

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 	Foreign Currency Translation and Transaction Gains and Losses	
      The local currencies are generally the functional currency of the Company’s foreign operations. Foreign currency denominated assets and liabilities are translated at end-of-period rates of exchange. Revenues, expenses and cash flows are translated at weighted-average rates of exchange for the period. The resulting currency translation adjustments are accumulated and reported as a separate component of member’s equity and are not included in the determination of the results of operations. Foreign currency transaction gains or losses are reported in results of operations. The Company recognized foreign currency transaction gains of $0.3 million and $0.5 million for the period from December 6, 2003 to December 31, 2003 and for the period from January 1, 2003 to December 5, 2003, respectively. For the years ended December 31, 2002 and 2001, the Company recognized $0.8 million and $1.6 million, respectively.

 	Concentrations of Credit Risk	
      Financial instruments, which potentially subject the Company to concentrations of credit risk, consist primarily of cash, accounts receivable, notes receivable and investments in debt securities. Cash accounts are generally held in government insured banks. Accounts receivable, notes receivable and derivative instruments are concentrated within entities engaged in the energy industry. These industry concentrations may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. Receivables are generally not collateralized; however, the Company believes the credit risk posed by industry concentration is offset by the diversification and credit worthiness of its customer base.

 	Pensions	
      The determination of the Company’s obligation and expenses for pension benefits is dependent on the selection of certain assumptions. These assumptions determined by management include the discount rate, the expected rate of return on plan assets and the rate of future compensation increases. Actuarial consultants use assumptions for such items as retirement age. The assumptions used may differ materially from actual results, which may result in a significant impact to the amount of pension obligation or expense recorded.

 	Use of Estimates in Financial Statements	
      The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenue and expenses during the reporting period. Actual results may differ from those estimates.

      In recording transactions and balances resulting from business operations, the Company uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, uncollectible accounts and the valuation of long-term energy commodities contracts, among others. In addition, estimates are used to test long-lived assets for impairment and to determine fair value of impaired assets. As better information becomes available (or actual amounts are determinable), the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

3.	Emergence from Bankruptcy and Fresh Start Reporting	
      In accordance with the requirements of push down accounting, the Company’s fair value of $771.3 million was allocated to the Company’s assets and liabilities based on their individual estimated fair values. A third party was used to complete an independent appraisal of the Company’s tangible assets, intangible assets, contracts and equity investments.

      The determination of the fair value of the Company’s assets and liabilities was based on a number of estimates and assumptions, which are inherently subject to significant uncertainties and contingencies.

12

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      Due to the adoption of push down accounting as of December 5, 2003, the Reorganized Company’s consolidated balance sheets, consolidated statements of operations and cash flows have not been prepared on a consistent basis with the Predecessor Company’s consolidated financial statements and are not comparable in certain respects to the consolidated financial statements prior to the application of push down accounting. A black line has been drawn on the accompanying consolidated financial statements to separate and distinguish between the Reorganized Company and the Predecessor Company. The effects of the push down accounting adjustments on the Company’s consolidated balance sheet as of December 5, 2003, were as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor	 	 	 	Reorganized	
 	 	Company	 	 	 	Company	
 	 	December 5,	 	Push Down	 	December 6,	
 	 	2003	 	Adjustments	 	2003	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
ASSETS	
Current assets	 	 	 	 	 	 	 	 	 	 	 	 	
 	Cash and cash equivalents	 	$	125,914	 	 	$	—	 	 	$	125,914	 	
 	Restricted cash	 	 	44,802	 	 	 	—	 	 	 	44,802	 	
 	Accounts receivable	 	 	39,072	 	 	 	—	 	 	 	39,072	 	
 	Accounts receivable — affiliates	 	 	5,893	 	 	 	 	 	 	 	5,893	 	
 	Current portion of notes receivable	 	 	64,720	 	 	 	—	 	 	 	64,720	 	
 	Inventory	 	 	16,178	 	 	 	—	 	 	 	16,178	 	
 	Prepayments and other current assets	 	 	4,417	 	 	 	190	 (A)	 	 	4,607	 	
 	Current assets — discontinued operations	 	 	13,148	 	 	 	—	 	 	 	13,148	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total current assets	 	 	314,144	 	 	 	190	 	 	 	314,334	 	
Net property, plant and equipment	 	 	478,226	 	 	 	(30,769	)(A)	 	 	447,457	 	
Equity investments in affiliates	 	 	394,643	 	 	 	(67,845	)(B)	 	 	326,798	 	
Notes receivable, less current portion	 	 	383,379	 	 	 	44,269	 (C)	 	 	427,648	 	
Notes receivable — affiliates, less current	 	 	 	 	 	 	 	 	 	 	 	 	
 	portion	 	 	107,412	 	 	 	—	 	 	 	107,412	 	
Derivative instruments valuation	 	 	66,442	 	 	 	—	 	 	 	66,442	 	
Other assets	 	 	51	 	 	 	—	 	 	 	51	 	
Noncurrent assets — discontinued operations	 	 	50,474	 	 	 	(2,569	)(G)	 	 	47,905	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total assets	 	$	1,794,771	 	 	$	(56,724	)	 	$	1,738,047	 	

	 	 	 	

	 	 	 	

	 	
 	
LIABILITIES AND MEMBER’S EQUITY	
Current liabilities	 	 	 	 	 	 	 	 	 	 	 	 	
 	Current portion of long-term debt	 	$	41,141	 	 	$	30,996	 (C)	 	$	72,137	 	
 	Accounts payable	 	 	28,898	 	 	 	—	 	 	 	28,898	 	
 	Accounts payable — affiliate	 	 	15,385	 	 	 	—	 	 	 	15,385	 	
 	Accrued income tax	 	 	17,023	 	 	 	—	 	 	 	17,023	 	
 	Accrued liabilities	 	 	10,154	 	 	 	—	 	 	 	10,154	 	
 	Other current liabilities	 	 	11,019	 	 	 	(8,201	)(A)	 	 	2,818	 	
 	Other current liabilities — Loy Yang	 	 	61,054	 	 	 	(61,054	)(F)	 	 	—	 	
 	Current liabilities — discontinued operations	 	 	107,415	 	 	 	(45,000	)(G)	 	 	62,415	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total current liabilities	 	 	292,089	 	 	 	(83,259	)	 	 	208,830	 	
Other liabilities	 	 	 	 	 	 	 	 	 	 	 	 	
 	Long-term debt	 	 	281,963	 	 	 	(25,077	)(C)	 	 	256,886	 	
 	Long-term debt — affiliates	 	 	196,259	 	 	 	—	 	 	 	196,259	 	
 	Deferred income taxes	 	 	149,203	 	 	 	12,705	 (D)	 	 	161,908	 	
 	Postretirement and other benefit obligations	 	 	11,399	 	 	 	3,340	 (E)	 	 	14,739	 	
 	Derivative instruments valuation	 	 	108,801	 	 	 	—	 	 	 	108,801	 	
 	Other long-term obligations	 	 	17,240	 	 	 	(2,775	)(A)	 	 	14,465	 	
 	Noncurrent liabilities — discontinued operations	 	 	9,533	 	 	 	(4,631	)(G)	 	 	4,902	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total liabilities	 	 	1,066,487	 	 	 	(99,697	)	 	 	966,790	 	

	 	 	 	

	 	 	 	

	 	
13

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor	 	 	 	Reorganized	
 	 	Company	 	 	 	Company	
 	 	December 5,	 	Push Down	 	December 6,	
 	 	2003	 	Adjustments	 	2003	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Member’s equity	 	 	 	 	 	 	 	 	 	 	 	 	
 	Member’s contributions	 	 	973,690	 	 	 	(202,433	)	 	 	771,257	 	
 	Accumulated net loss	 	 	(275,266	)	 	 	275,266	 	 	 	—	 	
 	Accumulated OCI	 	 	29,860	 	 	 	(29,860	)	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total member’s equity	 	 	728,284	 	 	 	42,973	 (H)	 	 	771,257	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total liabilities and member’s equity	 	$	1,794,771	 	 	$	(56,724	)	 	$	1,738,047	 	

	 	 	 	

	 	 	 	

	 	

 
 	 	 	
(A)	 	Results of allocating the equity value in conformity with the purchase method of accounting for business combinations. These allocations were based on valuations obtained from independent appraisers.	
 	 	 	
(B)	 	Includes the adjustment of carrying amount of investment in affiliates to fair value as determined by independent appraisers.	
 	 	 	
(C)	 	Reflects management’s estimate, based on current market interest rates as of December 5, 2003, of the fair value of notes receivable, notes payable and other debt instruments.	
 	 	 	
(D)	 	Reflects the adjustment to income tax liabilities due to push down accounting.	
 	 	 	
(E)	 	Adjustment to postretirement and other benefit obligations in order to reflect the accumulated benefit obligation liability based on independent actuarial reports.	
 	 	 	
(F)	 	In 2003, the Company became committed to sell its investment in Loy Yang. Consequently, the Company was required to recognize losses related to unfavorable forward currency adjustments of $61.1 million, which were recorded in other current liabilities. In connection with pushdown accounting, the liability and related currency translation adjustments balance were eliminated.	
 	 	 	
(G)	 	Pushdown accounting adjustments affected Hsin Yu that was continuing at the time of pushdown. Subsequent to December 6, 2003, Hsin Yu qualified as discontinued operations and was restated as such.	
 	 	 	
(H)	 	The change in member’s equity reflects the revaluation of the Company’s consolidated balance sheet and equity recapitalization in accordance with push down accounting procedures. Also included is a $61.1 million adjustment related to other comprehensive income — currency translation adjustments, the offset of which was recorded in other current liabilities as discussed in (F) above.	

4.	Discontinued Operations	
      SFAS No. 144 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, the Company’s management considered cash flow analyses, bids and offers related to those assets and businesses. This amount is included in income(loss) on discontinued operations, net of income taxes in the accompanying consolidated statements of operations. In accordance with the provisions of SFAS No. 144, assets held for sale will not be depreciated commencing with their classification as such.

      The Company has classified certain business operations, and gains/losses recognized on sale, as discontinued operations for projects that were sold or have met the required criteria for such classification.

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

      Summarized results of operations of the discontinued operations were as follows. For the period from December 6, 2003 to December 31, 2003, discontinued results of operations include the Company’s Hsin Yu Project. For the period from January 1, 2003 to December 5, 2003, discontinued results of operations include

14

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

the Company’s Hsin Yu, Killingholme, Cahua and Energia Pacasmayo projects. For the years ended December 31, 2002 and December 31, 2001, discontinued results of operations included the Company’s Hsin Yu, Csepel, Entrade, Killingholme, Cahua and Energia Pacasmayo projects. During the second quarter of 2004, the Company determined that Hsin Yu met the criteria for discontinued operations, and accordingly, all periods presented have been restated.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	For the	
 	 	December 6,	 	January 1,	 	Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Operating revenues	 	$	4,213	 	 	$	98,224	 	 	$	644,969	 	 	$	450,835	 	
Operating and other expenses	 	 	4,435	 	 	 	93,504	 	 	 	1,224,079	 	 	 	405,412	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Pre-tax (loss) income from operations of discontinued components	 	 	(222	)	 	 	4,720	 	 	 	(579,110	)	 	 	45,423	 	
Income tax (benefit) expense	 	 	—	 	 	 	(337	)	 	 	(7,412	)	 	 	5,147	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
(Loss) income from operations of discontinued components	 	 	(222	)	 	 	5,057	 	 	 	(571,698	)	 	 	40,276	 	
Disposal of discontinued components — net of income taxes	 	 	—	 	 	 	164,126	 	 	 	18,690	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Net income (loss) on discontinued operations	 	$	(222	)	 	$	169,183	 	 	$	(553,008	)	 	$	40,276	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
      Operating and other expenses for the period from December 6, 2003 to December 31, 2003, January 1, 2003 to December 5, 2003, and for the years ended December 31, 2002 and 2001, shown in the table above included asset impairment charges of approximately $0, $0 million, $599.8 million and $0, respectively. The 2002 charges are comprised of approximately $477.9 million for the Killingholme project and $121.9 for the Hsin Yu project.

15

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The components of income tax benefit attributable to discontinued operations were as follows:

 	 	Reorganized	 	Predecessor	
 	 	Company	 	Company	

	 	

	
 	 	For the Period from	 	For the Period from	 	 	
 	 	December 6, 2003 to	 	January 1, 2003 to	 	 	
Discontinued Operations:	 	December 31, 2003	 	December 5, 2003	 	2002	 	2001	

	 	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands)	
Current	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	U.S. 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	
 	Foreign	 	 	—	 	 	 	(741	)	 	 	(8,064	)	 	 	(4,293	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	—	 	 	 	(741	)	 	 	(8,064	)	 	 	(4,293	)	
Deferred	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	U.S. 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	Foreign	 	 	—	 	 	 	404	 	 	 	652	 	 	 	9,440	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	—	 	 	 	404	 	 	 	652	 	 	 	9,440	 	
Subtotal	 	 	—	 	 	 	(337	)	 	 	(7,412	)	 	 	5,147	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Disposal of discontinued components — gain (net)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	U.S. 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	Foreign	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total income tax (benefit) expense	 	$	—	 	 	$	(337	)	 	$	(7,412	)	 	$	5,147	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
16

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The assets and liabilities of the discontinued operations are reported in the December 31, 2003, the December 6, 2003 and December 31, 2002 consolidated balance sheets as discontinued operations. The major classes of assets and liabilities are presented in the following table.
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Cash	 	$	721	 	 	$	1,002	 	 	$	27,648	 	
Restricted cash	 	 	—	 	 	 	—	 	 	 	1,396	 	
Receivables, net	 	 	5,121	 	 	 	5,920	 	 	 	30,511	 	
Inventory	 	 	2,784	 	 	 	2,742	 	 	 	16,060	 	
Other current assets	 	 	3,989	 	 	 	3,484	 	 	 	38,185	 	

	 	 	 	

	 	 	 	

	 	
Current assets — discontinued operations	 	$	12,615	 	 	$	13,148	 	 	$	113,800	 	

	 	 	 	

	 	 	 	

	 	
Property, plant and equipment, net	 	$	39,838	 	 	$	40,345	 	 	$	371,993	 	
Other noncurrent assets	 	 	7,638	 	 	 	7,560	 	 	 	105,766	 	

	 	 	 	

	 	 	 	

	 	
Noncurrent assets — discontinued operations	 	$	47,476	 	 	$	47,905	 	 	$	477,759	 	

	 	 	 	

	 	 	 	

	 	
Current portion of long-term debt	 	$	40,820	 	 	$	39,980	 	 	$	453,742	 	
Accounts payable — trade	 	 	16,401	 	 	 	17,039	 	 	 	21,436	 	
Accrued interest	 	 	—	 	 	 	—	 	 	 	728	 	
Other current liabilities	 	 	5,772	 	 	 	5,396	 	 	 	56,610	 	

	 	 	 	

	 	 	 	

	 	
Current liabilities — discontinued operations	 	$	62,993	 	 	$	62,415	 	 	$	532,516	 	

	 	 	 	

	 	 	 	

	 	
Long-term debt	 	$	—	 	 	$	—	 	 	$	36,772	 	
Deferred income taxes	 	 	—	 	 	 	—	 	 	 	139,900	 	
Other long-term obligations	 	 	3,729	 	 	 	4,902	 	 	 	26,367	 	

	 	 	 	

	 	 	 	

	 	
Noncurrent liabilities — discontinued operations	 	$	3,729	 	 	$	4,902	 	 	$	203,039	 	

	 	 	 	

	 	 	 	

	 	
      Hsin Yu — During 2002, the Company recorded an impairment charge of $121.9 million. During the second quarter 2004, the Company entered into an agreement to sell its interest in Hsin Yu power generating facility (located in Taipei, Taiwan) to a minority interest shareholder, Asia Pacific Energy Development Company Ltd, which reached financial closing in May 2004. Upon completion of the transaction, the Company received net cash proceeds of $1.0 million, resulting in a gain of approximately $10.3 million resulting from the negative equity in the project.

      Csepel and Entrade — In September 2002, the Company announced that it had reached agreements to sell its Csepel power generating facilities (located in Budapest, Hungary) and its interest in Entrade (an electricity trading business headquartered in Prague) to Atel, an independent energy group headquartered in Switzerland. The sales of Csepel and Entrade closed before year end and resulted in cash proceeds of $92.6 million (net of cash transferred to NRG Energy of $44.1 million) and a gain of approximately $24.0 million.

      Killingholme — During third quarter 2002, the Company recorded an impairment charge of $477.9 million. In January 2003, the Company completed the sale of its interest in the Killingholme project to its lenders for a nominal value and forgiveness of outstanding debt with a carrying value of approximately $360.1 million at December 31, 2002. The sale of the Company’s interest in the Killingholme project and the release of debt obligations resulted in a gain on sale in the first quarter of 2003 of approximately $201.0 million. The gain

17

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

results from the write-down of the project’s assets in the third quarter of 2002 below the carrying value of the related debt.

      Peru Projects — In November 2003, the Company completed the sale of the Cahua and Energia Pacasmayo (Peruvian Assets) resulting in net cash proceeds of approximately $16.2 million and a loss of $36.9 million. In addition, the Company received an additional consideration adjustment of approximately $0.6 million during 2004.

5.	Write Downs and (Gains)/Losses on Sales of Equity Method Investments	
      Investments accounted for by the equity method are reviewed for impairment in accordance with APB Opinion No. 18. APB Opinion No. 18, requires that a loss in value of an investment that is other than a temporary decline should be recognized. Gains are recognized on completion of the sale. Write downs and (gains)/losses on sales of equity method investments recorded in operating expenses in the consolidated statements of operations include the following:

 	 	Predecessor Company	

	
 	 	For the	 	 	
 	 	Period from	 	 	
 	 	January 1,	 	For the	
 	 	2003 to	 	Year Ended	
 	 	December 5,	 	December 31,	
 	 	2003	 	2002	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Kondapalli	 	$	(45	)	 	$	12,751	 	
ECKG	 	 	(7,938	)	 	 	—	 	
Loy Yang	 	 	146,354	 	 	 	111,383	 	
Energy Development Limited (“EDL”)	 	 	—	 	 	 	13,382	 	
Collinsville Power Station	 	 	—	 	 	 	1,630	 	

	 	 	 	

	 	
 	Total write downs and losses of equity method investment	 	$	138,371	 	 	$	139,146	 	

	 	 	 	

	 	
      Kondapalli — In the fourth quarter of 2002, the Company wrote down its investment in Kondapalli by $12.7 million due to recent estimates of sales value, which indicated an impairment of its book value that was considered to be other than temporary. On January 30, 2003, the Company signed a sale agreement with the Genting Group of Malaysia, (“Genting”) to sell its 30% interest in Lanco Kondapalli Power Pvt Ltd, (“Kondapalli”) and a 74% interest in Eastern Generation Services (India) Pvt Ltd (the “O&M company”). Kondapalli is based in Hyderabad, Andhra Pradesh, India, and is the owner of a 368 MW natural gas fired combined cycle gas turbine. In the first quarter of 2003, the Company wrote down its investment in Kondapalli by $1.3 million based on the final sale agreement. The sale closed on May 30, 2003, resulting in net cash proceeds of approximately $24 million and a gain of approximately $1.4 million, net of selling expenses. The gain resulted from incurring lower selling costs than estimated as part of the first quarter impairment.

      ECKG — In September 2002, the Company announced that it had reached agreement to sell its 44.5% interest in the ECKG power station in connection with its Csepel power generating facilities, and its interest in Entrade, an electricity trading business, to Atel, an independent energy group headquartered in Switzerland. The transaction closed in January 2003 and resulted in cash proceeds of $65.3 million and a net gain of $7.9 million.

      Loy Yang — Based on a third party market valuation and bids received in response to marketing Loy Yang for possible sale, the Company recorded a write down of its investment of approximately $111.4 million during 2002 ($53.6 million during the third quarter and an additional $57.8 million during the fourth quarter). This write-down reflected management’s belief that the decline in fair value of the investment was other than temporary.

18

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      In May 2003, the Company entered into negotiations that culminated in the completion of a Share Purchase Agreement to sell 100% of the Loy Yang project. Completion of the sale was subject to various conditions. Upon completion, proceeds from the sale were estimated at approximately $25.0 million to $31.0 million; consequently, the Company recorded an additional impairment charge of approximately $146.4 million during 2003. The impairment charge recorded included approximately $61.1 million of foreign currency translation losses previously recorded in accumulated other comprehensive income (loss), which was reversed upon adoption of push down accounting. In April 2004, the Company completed the sale of its interest in Loy Yang (See Note 23 Subsequent Events).

      Energy Development Limited — On July 25, 2002, the Company announced that it completed the sale of its ownership interests in an Australian energy company, Energy Development Limited (“EDL”). EDL is a listed Australian energy company engaged in the development and management of an international portfolio of projects with a particular focus on renewable and waste fuels. During the third quarter of 2002, the Company recorded a write-down of the investment of approximately $13.4 million to write down the carrying value of its equity investment due to the pending sale. In October 2002, the Company received proceeds of $78.5 million (AUD), (approximately $43.9 million (USD)), in exchange for its ownership interest in EDL with the closing of the transaction.

      Collinsville Power Station — Based on third party market valuation and bids received in response to marketing the investment for possible sale, the Company recorded a write down of its investment of approximately $1.6 million during the second quarter of 2002. In August 2002, the Company announced that it had completed the sale of its 50% interest in the 192 MW Collinsville Power Station in Australia, to the Company’s partner, a subsidiary of Transfield Services Limited for $8.6 million (AUD), (approximately $4.8 million (USD)). The Company’s ultimate loss on the sale of Collinsville Power Station was approximately $1.6 million, which had been recorded in the second quarter of 2002.

6.	Restructuring and Impairment Charges	
      The Company reviewed the recoverability of its long-lived assets in accordance with the guidelines of SFAS No. 144. As a result of this review, the Company recorded impairment charges of $3.4 million and $167.5 million for the period from January 1, 2003 to December 5, 2003 and for the year ended December 31, 2002, respectively, as shown in the table below.

      To determine whether an asset was impaired, the Company compared asset carrying values to total future estimated undiscounted cash flows. Separate analyses were completed for assets or groups of assets at the lowest level for which identifiable cash flows were largely independent of the cash flows of other assets and liabilities. The estimates of future cash flows included only future cash flows, net of associated cash outflows, directly associated with and expected to arise as a result of the Company’s assumed use and eventual disposition of the asset. Cash flow estimates associated with assets in service were based on the asset’s existing service potential. The cash flow estimates may include probability weightings to consider possible alternative courses of action and outcomes, given the uncertainty of available information and prospective market conditions.

      If an asset was determined to be impaired based on the cash flow testing performed, an impairment loss was recorded to write down the asset to its fair value. Estimates of fair value were based on prices for similar assets and present value techniques. Fair values determined by similar asset prices reflect the Company’s current estimate of recoverability from expected marketing of project assets. For fair values determined by projected cash flows, the fair value represents a discounted cash flow amount over the remaining life of each project that reflects project-specific assumptions for long-term power pool prices, escalated future project operating costs, and expected plant operation given assumed market conditions.

19

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      Restructuring and impairment charges included the following asset impairments (realized gains) for the period from January 1, 2003 to December 5, 2003 and for the year ended December 31, 2002:

 	 	 	 	Predecessor Company	

	
 	 	 	 	For the	 	 	
 	 	 	 	Period from	 	 	
 	 	 	 	January 1,	 	For the Year	
 	 	 	 	2003 to	 	Ended	
 	 	Project	 	December 5,	 	December 31,	
Project Name	 	Status	 	2003	 	2002	

	 	

	 	

	 	

	
 	 	 	 	 	
 	 	 	 	(In thousands of dollars)	
Termo Rio	 	 	Terminated	 	 	$	6,400	 	 	$	3,319	 	
Langage (UK)	 	 	Terminated	 	 	 	(3,047	)	 	 	42,333	 	

	 	 	 	

	 	
Total impairment charges	 	 	 	 	 	 	3,353	 	 	 	45,652	 	
Other restructuring charges	 	 	 	 	 	 	576	 	 	 	7,849	 	

	 	 	 	

	 	
Total restructuring and impairment charges	 	 	 	 	 	$	3,929	 	 	$	53,501	 	

	 	 	 	

	 	
      Termo Rio — Termo Rio is a 1,040 MW green field cogeneration project located in the state of Rio de Janeiro, Brazil. Based on the project’s failure to meet certain key milestones, the Company exercised its rights under the project agreements to sell its debt and equity interests in the project to the Company’s partner. In addition to exercising its put option, the Company wrote off its investment in shares of Termo Rio as well as capitalized start-up costs for a total charge of $3.3 million in 2002. The Company is in arbitration over the amount of compensation it is to receive for its interests in the project. Based on continued negotiations aimed at settling the case and the positions of the parties in the arbitration, the Company recorded an impairment charge of $6.4 million to reflect its investment interest at the amount expected to be recovered through a sale. On March 8, 2004, the arbitral tribunal decided most, but not all, of the issues in the Company’s favor. The final amount of the arbitral award to NRG Energy has not been conclusively determined and the parties may seek to modify or challenge the award. The Company believes it will recover the amount it has recorded on its consolidated balance sheet.

      Langage (UK) — During the third quarter of 2002, the Company reviewed the recoverability of its Langage assets pursuant to SFAS No. 144 and recorded a charge of $42.3 million. In August 2003, the Company closed on the sale of Langage to Carlton Power Limited resulting in net cash proceeds of approximately $1.5 million, of which $1.0 million was received in 2003 and $0.5 million during the first quarter of 2004, and a net gain of approximately $3.1 million.

      In addition to asset impairment charges, the Company incurred $6.5 million of financial and legal advisor fees and $1.4 million in severance costs associated with the combining and restructuring of various international functions during 2002.

      There were no restructuring and impairment charges for the period from December 6, 2003 to December 31, 2003 or for the year ended December 31, 2001.

7.	Inventory	
      Inventory, which is valued at the lower of weighted average cost or market, consists of:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Fuel oil	 	$	504	 	 	$	210	 	 	$	189	 	
Coal	 	 	10,726	 	 	 	9,578	 	 	 	5,473	 	
Spare parts	 	 	6,670	 	 	 	6,390	 	 	 	4,997	 	

	 	 	 	

	 	 	 	

	 	
 	Total inventory	 	$	17,900	 	 	$	16,178	 	 	$	10,659	 	

	 	 	 	

	 	 	 	

	 	
20

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

8.	Notes Receivable	
      Notes receivable consists primarily of fixed and variable rate notes secured by equity interests in partnerships and joint ventures. The notes receivable are as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31,	 	December 6,	 	December 31,	
 	 	2003	 	2003	 	2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Notes receivables	 	 	 	 	 	 	 	 	 	 	 	 	
Termo Rio, 19.5%(1)	 	$	57,323	 	 	$	57,323	 	 	$	63,723	 	

	 	 	 	

	 	 	 	

	 	
 	Notes receivable — nonaffiliates	 	 	57,323	 	 	 	57,323	 	 	 	63,723	 	
Kladno Power (No. 1) B.V	 	 	—	 	 	 	—	 	 	 	2,442	 	
Kladno Power (No. 2) B.V. notes to various affiliates, noninterest bearing	 	 	—	 	 	 	—	 	 	 	46,801	 	
Saale Energie GmbH, indefinite maturity date, 4.75%-7.79%(2)	 	 	111,892	 	 	 	107,391	 	 	 	86,246	 	
Other	 	 	21	 	 	 	21	 	 	 	19	 	

	 	 	 	

	 	 	 	

	 	
 	Notes receivable — affiliates	 	 	111,913	 	 	 	107,412	 	 	 	135,508	 	
Other	 	 	 	 	 	 	 	 	 	 	 	 	
Saale Energie GmbH, due August 31, 2021, 13.88% (direct financing lease)(3)	 	 	451,449	 	 	 	435,045	 	 	 	366,418	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	620,685	 	 	 	599,780	 	 	 	565,649	 	
Less: Current maturities	 	 	64,720	 	 	 	64,720	 	 	 	51,730	 	

	 	 	 	

	 	 	 	

	 	
 	 	$	555,965	 	 	$	535,060	 	 	$	513,919	 	

	 	 	 	

	 	 	 	

	 	

 	 	
(1) 	See Note 6 — Restructuring and Impairment Charges for an explanation of the note receivable.	
 	 	
(2) 	Saale Energie GmbH entered into a note receivable with Kraftwerke Schkopau GBR. Kraftwerke Schkopau GBR is an affiliate of the Company and a wholly owned subsidiary of NRG Energy,. The note was used to fund the initial capital contribution and project liquidity shortfalls during construction. The note is subject to repayment upon the disposition of the Schkopau power plant.	
 	 	
(3) 	At December 31, 2003, expected cash payments for each of the five succeeding years is EUR 57.1 million (US$71.8 million) per year. See Note 13 — Long Term Debt and Capital Leases for further details concerning the direct financing lease.	
21

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

9.	Property, Plant and Equipment	
      The major classes of property, plant and equipment were as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Predecessor	 	 	
 	 	 	 	Reorganized Company	 	Company	 	 	

	 	

	 	Average	
 	 	Depreciable	 	December 31,	 	December 6,	 	December 31,	 	Remaining	
 	 	Lives	 	2003	 	2003	 	2002	 	Useful Life	

	 	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Facilities and equipment	 	 	10-30 years	 	 	$	323,837	 	 	$	316,453	 	 	$	308,866	 	 	 	19 years	 	
Land and improvements	 	 	 	 	 	 	15,717	 	 	 	15,350	 	 	 	13,567	 	 	 	 	 	
Office furnishings and equipment	 	 	3-15 years	 	 	 	2,081	 	 	 	2,061	 	 	 	1,518	 	 	 	3 years	 	
Construction work in progress	 	 	 	 	 	 	118,056	 	 	 	113,593	 	 	 	30,480	 	 	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	 	 	
 	Total property, plant and equipment	 	 	 	 	 	 	459,691	 	 	 	447,457	 	 	 	354,431	 	 	 	 	 	
Accumulated depreciation	 	 	 	 	 	 	(1,467	)	 	 	—	 	 	 	(33,683	)	 	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	 	 	
Property, plant and equipment, net	 	 	 	 	 	$	458,224	 	 	$	447,457	 	 	$	320,748	 	 	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	 	 	

10.	Investments Accounted for by the Equity Method	
      The Company had investments in various international energy projects. The equity method of accounting is applied to such investments in affiliates, which include joint ventures and partnerships, because the Company has significant influence over operating and financial policies of the projects. Under this method, equity in the net income or losses of these projects, is reflected as equity in earnings of unconsolidated affiliates.

      A summary of certain of the Company’s more significant equity-method investments, which were in operation at December 31, 2003, is as follows:
 	 	 	 	 	 	 	
 	 	 	 	Economic	
Name	 	Geographic Area	 	Interest	

	 	

	 	

	
Gladstone Power Station	 	Australia	 	 	38%	 	
Loy Yang Power A	 	Australia	 	 	25%	 	
MIBRAG GmbH	 	Europe	 	 	50%	 	
Enfield	 	Europe	 	 	25%	 	
Scudder LA Power Fund I	 	Latin America	 	 	25%	 	
      In addition the Company had a 30% economic interest in Kondapalli, which was purchased in 2001 and sold in 2003; a 44.5% economic interest in ECKG, which was purchased in 1995 and sold in 2003; a 50% economic interest in Collinsville Power Station, which was purchased in 1998 and sold in 2002; and a 26.3% interest in EDL, which was purchased in 1997 and sold in 2002.

22

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      Summarized financial information for investments in unconsolidated affiliates accounted for under the equity method is as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	For the Period	 	For the Period	 	 	
 	 	from	 	from	 	For the Year Ended	
 	 	December 6, 2003	 	January 1, 2003	 	December 31,	
 	 	to	 	to	 	

	
 	 	December 31, 2003	 	December 5, 2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Operating revenues	 	$	98,990	 	 	$	915,798	 	 	$	993,543	 	 	$	843,479	 	
Costs and expenses	 	 	(96,342	)	 	 	(1,000,974	)	 	 	(896,588	)	 	 	(798,015	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	Net income (loss)	 	$	2,648	 	 	$	(85,176	)	 	$	96,955	 	 	$	45,464	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Current assets	 	$	369,800	 	 	$	378,422	 	 	$	515,614	 	 	$	571,807	 	
Noncurrent assets	 	 	4,621,844	 	 	 	4,482,307	 	 	 	4,746,810	 	 	 	4,302,721	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	Total assets	 	$	4,991,644	 	 	$	4,860,729	 	 	$	5,262,424	 	 	$	4,874,528	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Current liabilities	 	$	779,580	 	 	$	734,309	 	 	$	680,512	 	 	$	516,730	 	
Noncurrent liabilities	 	 	3,524,886	 	 	 	3,450,667	 	 	 	3,227,514	 	 	 	3,116,346	 	
Equity	 	 	687,178	 	 	 	675,753	 	 	 	1,354,398	 	 	 	1,241,452	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	Total liabilities and equity	 	$	4,991,644	 	 	$	4,860,729	 	 	$	5,262,424	 	 	$	4,874,528	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
The Company’s share of equity	 	$	287,320	 	 	$	283,478	 	 	$	447,428	 	 	$	421,012	 	
The Company’s carrying value(2)	 	 	332,617	 	 	 	326,798	 	 	 	309,748	 	 	 	440,954	 	
The Company’s share of net income(1)	 	 	1,707	 	 	 	61,900	 	 	 	49,297	 	 	 	56,922	 	

 	 	
(1) 	Included in costs and expenses for the period ended December 5, 2003, was an impairment charge recorded at the Loy Yang Project Company for AUD$275.2 million (US$177.8 million). The Company reports impairment separately in write downs and losses on sales of equity method investments; consequently, the net loss amount for the total results of unconsolidated affiliates is negative while the Company’s equity in earnings of unconsolidated affiliates is positive.	
 	 	
(2) 	In 2002, the Company’s carrying value was significantly lower than the Company’s share of equity due to the impairment of Loy Yang recorded by the Company of $111.4 million. See Note 5 — Write Downs and (Gains)/Losses on Sales of Equity Method Investments. In 2003, the Company’s carrying value was impacted by an additional impairment charge of $146.4 million related to Loy Yang, offset by unrealized gains recorded under SFAS No. 133 and movements in foreign currency exchange rates.	
      The Company has ownership in three companies that were considered significant as defined by applicable SEC regulations as of December 31, 2003, Gladstone Power Station UJV (“Gladstone”), Mibrag GmbH (“Mibrag”) and Loy Yang Power (“Loy Yang”). The Company accounts for these investments using the equity method. These three businesses operate power generation facilities and are subject to the risks inherent to those businesses, including (but not limited to) fluctuations in prices for generated power and fuels used in the power generation process. These businesses attempt to mitigate such risks by primarily entering into long term delivery and supply agreements to the extent applicable as more fully described below.

      The Company owns a 37.5% interest in Gladstone, an unincorporated joint venture (“UJV”) which operates a 1,680 megawatt coal-fueled power generation facility in Queensland, Australia. The operations of

23

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

the power generation facility are managed by the majority partner in the joint venture using employees of affiliates of the Company. Operating expenses incurred in connection with the operation of the facility are funded by each of the partners in proportion to their ownership interests. Coal is sourced from a mining operation owned and operated by the Company’s joint venture partners and other investors under a long term supply agreement. The Company and its joint venture partners receive a majority of their respective share of revenues directly from customers and are directly responsible and liable for project related debt, all in proportion to their ownership interests in the UJV. Power generated by the facility is sold on the national market under a long term agreement. The following tables summarize financial information for the Company’s interest in, and revenue and costs directly attributable to the Company’s investment in Gladstone unincorporated joint venture.

      Results of operations:

 	 	For the Year Ended	

	
 	 	2003	 	2002	 	2001	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Operating revenues	 	$	73,696	 	 	$	64,311	 	 	$	60,895	 	
Operating income	 	 	19,052	 	 	 	16,387	 	 	 	15,413	 	
Net income	 	 	9,049	 	 	 	8,449	 	 	 	5,904	 	
      Financial position:

 	 	December 31,	

	
 	 	2003	 	2002	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Current assets	 	$	34,484	 	 	$	21,952	 	
Other assets	 	 	215,472	 	 	 	162,476	 	

	 	 	 	

	 	
 	Total assets	 	$	249,956	 	 	$	184,428	 	

	 	 	 	

	 	
Current liabilities	 	$	22,970	 	 	$	15,214	 	
Other liabilities	 	 	146,864	 	 	 	116,984	 	
Equity	 	 	80,122	 	 	 	52,230	 	

	 	 	 	

	 	
 	Total liabilities and equity	 	$	249,956	 	 	$	184,428	 	

	 	 	 	

	 	
      The Company also owns a 50% interest in Mibrag. Located near Leipzig, Germany, Mibrag owns and manages a coal mining operation, three lignite fueled power generation facilities and other related businesses. Approximately 50% of the power generated by Mibrag is used to support its mining operations, with the remainder sold to a German utility company. A portion of the coal from Mibrag’s mining operation is used to fuel the power generation facilities, but a majority of the mined coal is sold primarily to two major customers, including Schkopau, a subsidiary of the Company. A significant portion of the sales of Mibrag are made pursuant to long-term coal and energy supply contracts. The following tables summarize financial information for Mibrag, including interests owned by the Company and other parties for the periods shown below:

      Results of operations:

 	 	For the Year Ended	

	
 	 	2003	 	2002	 	2001	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Operating revenues	 	$	400,952	 	 	$	320,192	 	 	$	279,095	 	
Operating income	 	 	61,835	 	 	 	66,663	 	 	 	54,252	 	
Net income	 	 	45,875	 	 	 	56,224	 	 	 	43,640	 	
24

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      Financial position:

 	 	December 31,	

	
 	 	2003	 	2002	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Current assets	 	$	164,780	 	 	$	204,257	 	
Other assets	 	 	1,206,934	 	 	 	1,115,738	 	

	 	 	 	

	 	
 	Total assets	 	$	1,371,714	 	 	$	1,319,995	 	

	 	 	 	

	 	
Current liabilities	 	$	23,198	 	 	$	68,630	 	
Other liabilities	 	 	1,031,606	 	 	 	947,151	 	
Equity	 	 	316,910	 	 	 	304,214	 	

	 	 	 	

	 	
 	Total liabilities and equity	 	$	1,371,714	 	 	$	1,319,995	 	

	 	 	 	

	 	
      Until the completion of the sale of its interests in April 2004 (see Notes 5 and 23), the Company held a 25.4% equity interest in Loy Yang, a partnership which operates a 2,100 megawatt power generation facility and an adjacent coal mine in Victoria, Australia. The financial data shown below does not include the effect of impairment charges recorded of $146.3 million and $111.4 million recorded by the Company in 2003 and 2002, respectively (see Note 5). The following tables summarize financial information for Loy Yang, including interests owned by the Company and other parties for the periods shown below:

 	 	For the Year Ended	

	
 	 	2003	 	2002	 	2001	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Operating revenues	 	$	382,561	 	 	$	367,278	 	 	$	313,937	 	
Operating income	 	 	17,798	 	 	 	(76,962	)	 	 	179,907	 	
Net (loss) income	 	 	(160,206	)	 	 	(427,971	)	 	 	10,907	 	
      Financial position:

 	 	December 31,	

	
 	 	2003	 	2002	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Current assets	 	$	131,994	 	 	$	163,504	 	
Other assets	 	 	2,879,434	 	 	 	2,273,555	 	

	 	 	 	

	 	
 	Total assets	 	$	3,011,428	 	 	$	2,437,059	 	

	 	 	 	

	 	
Current liabilities	 	$	705,715	 	 	$	555,668	 	
Other liabilities	 	 	2,156,718	 	 	 	1,628,286	 	
Equity	 	 	148,995	 	 	 	253,105	 	

	 	 	 	

	 	
 	Total liabilities and equity	 	$	3,011,428	 	 	$	2,437,059	 	

	 	 	 	

	 	

11.	Asset Retirement Obligation	
      SFAS No. 143, Accounting for Asset Retirement Obligations, requires an entity to recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred. Upon initial recognition of a liability for an asset retirement obligation, an entity shall capitalize an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Retirement obligations associated with long-lived assets included within the scope of

25

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes and written or oral contracts, including obligations arising under the doctrine of promissory estoppel.

      The Company had previously recorded its asset retirement obligation and, as a result, the adoption of SFAS No. 143 on January 1, 2003, had no financial statement impact.

      Upon the acquisition of Flinders Power, in August 2000 (primarily the Northern Power Station, the Playford Power Station and the Leigh Creek mining operation), the Company recognized an obligation in the amount of $3.7 million as part of its opening balance sheet under purchase accounting related to an obligation to decommission these facilities at the end of their useful lives. Subsequently, the obligation has grown to $5.8 million at December 31, 2002, through periodic recognition of accretion expense, which was significantly impacted by movement in foreign currency exchange rates during 2003.

      The following represents the balances of the asset retirement obligation as of January 1, 2003, and related accretion for the period from January 1, 2003 to December 5, 2003, and for the period from December 6, 2003 to December 31, 2003, which is included in other long-term obligations in the consolidated balance sheet.

 	 	Predecessor Company	

	
 	 	Beginning	 	Accretion for	 	Ending	
 	 	Balance	 	Period Ended	 	Balance	
 	 	January 1,	 	December 5,	 	December 5,	
 	 	2003	 	2003	 	2003	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Australia	 	$	5,834	 	 	$	3,282	 	 	$	9,116	 	

 	 	Reorganized Company	

	
 	 	 	 	Accretion for	 	 	
 	 	Beginning	 	Period	 	Ending	
 	 	Balance	 	December 6 to	 	Balance	
 	 	December 6,	 	December 31,	 	December 31,	
 	 	2003	 	2003	 	2003	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Australia	 	$	9,116	 	 	$	322	 	 	$	9,438	 	

12.	Derivative Instruments and Hedging Activities	
      On January 1, 2001, the Company has adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 137, SFAS No. 138 and SFAS No. 149. SFAS No. 133 requires the Company to record all derivatives on the balance sheet at fair value. Changes in the fair value of nonhedge derivatives will be immediately recognized in earnings. The criteria used to determine if hedge accounting treatment is appropriate are (a) the designation of the hedge to an underlying exposure, (b) whether or not the overall risk is being reduced and (c) if there is a high degree of correlation between the value of the derivative instrument and the underlying obligation. Formal documentation of the hedging relationship, the nature of the underlying risk, the risk management objective, and the means by which effectiveness will be assessed is created at the inception of the hedge. Changes in fair values of derivatives accounted for as hedges will either be recognized in earnings as offsets to the changes in fair value of related hedged assets, liabilities and firm commitments or, for forecasted transactions, deferred and recorded as a component of other accumulated comprehensive income, (“OCI”) until the hedged transactions occur and are recognized in earnings. The ineffective portion of a hedging derivative instrument’s change in fair value will be immediately recognized in earnings. The Company also formally assesses both at inception and at least quarterly thereafter, whether the derivatives that are used in hedging transactions are highly effective in offsetting the changes in either the fair value or cash flows of the hedged item. This assessment includes all components of each derivative’s gain or loss unless otherwise noted. When it is determined that a derivative ceases to be a highly effective hedge, hedge accounting is discontinued.

26

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      SFAS No. 133 applies to the Company’s long-term power sales contracts, long-term fuel purchase contracts and other energy related commodities financial instruments used to mitigate variability in earnings due to fluctuations in spot market prices, hedge fuel requirements at generation facilities and protect investments in fuel inventories. SFAS No. 133 also applies to various interest rate swaps used to mitigate the risks associated with movements in interest rates and foreign exchange contracts to reduce the effect of fluctuating foreign currencies on foreign denominated investments and other transactions. At December 31, 2003, the Company had commodity contracts extending through December 2018.

      The adoption of SFAS No. 133 on January 1, 2001, resulted in the after tax unrealized gain/ loss of $14.7 million recorded to OCI related to previously deferred net gains/ losses on derivatives designated as cash flow hedges. In addition, the Company did not record any amount in its statement of operation as a cumulative effect of the change in accounting for derivative financial instruments.

Derivative Financial Instruments

 	Foreign Currency Exchange Rates	
      At December 31, 2003, December 6, 2003 and December 31, 2002, neither the Company nor its consolidating subsidiaries had any outstanding foreign currency exchange contracts.

 	Interest Rates	
      At December 31, 2003, December 6, 2003 and December 31, 2002, the Company’s consolidating subsidiaries had various interest-rate swap agreements with combined notional amounts of $154.9 million, $137.9 million and $109.4 million, respectively. These contracts are used to manage the Company’s exposure to changes in interest rates. If these swaps had been terminated at December 31, 2003, December 6, 2003 and December 31, 2002, the Company would have owed the counter-parties $4.3 million, $4.4 million and $8.7 million, respectively.

 	Energy Related Commodities	
      At December 31, 2003, December 6, 2003 and December 31, 2002, the Company had various energy related commodities financial instruments with combined notional amounts of $516.9 million, $504.8 million and $395.7 million, respectively. These financial instruments take the form of fixed price, floating price or indexed sales or purchases, options, such as puts or calls, basis transactions and swaps. These contracts are used to manage the Company’s exposure to commodity price variability in electricity and natural gas, oil and coal used to meet fuel requirements. If these contracts were terminated at December 31, 2003, December 6, 2003 and December 31, 2002, the Company would have paid $46.4 million, $40.0 million and $33.5 million, to counter-parties, respectively.

27

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 	Accumulated Other Comprehensive Income	
      The following table summarizes the effects of SFAS No. 133 on the Company’s other comprehensive income balance as of December 31, 2003:

 	 	Reorganized Company	

	
 	 	Energy	 	Interest	 	Foreign	 	 	
Gains (Losses)	 	Commodities	 	Rate	 	Currency	 	Total	

	 	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Accumulated OCI balance at December 6, 2003	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	
 	Mark to market of hedge contracts	 	 	(2,319	)	 	 	43	 	 	 	125	 	 	 	(2,151	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Accumulated OCI balance at December 31, 2003	 	$	(2,319	)	 	$	43	 	 	$	125	 	 	$	(2,151	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Losses expected to unwind from OCI during next 12 months	 	$	(980	)	 	$	(100	)	 	$	—	 	 	$	(1,080	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
      During the period ended December 31, 2003, the Company recorded a loss in OCI of approximately $2.2 million related to changes in the fair values of derivatives accounted for as hedges. The net balance in OCI relating to SFAS No. 133 as of December 31, 2003, was an unrecognized loss of approximately $2.2 million. The Company expects $1.1 million of deferred net losses on derivative instruments accumulated in OCI to be recognized in earnings during the next twelve months.

      The following table summarizes the effects of SFAS No. 133 on the Company’s other comprehensive income balance as of December 6, 2003:

 	 	Predecessor Company	

	
 	 	Energy	 	Interest	 	Foreign	 	 	
Gains (Losses)	 	Commodities	 	Rate	 	Currency	 	Total	

	 	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Accumulated OCI balance at January 1, 2003	 	$	99,448	 	 	$	(46,586	)	 	$	290	 	 	$	53,152	 	
 	Unwound from OCI during period	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Due to forecasted transactions probable of no longer occurring	 	 	—	 	 	 	32,025	 	 	 	—	 	 	 	32,025	 	
 	 	Due to unwinding of previously deferred amounts	 	 	(79,745	)	 	 	5,750	 	 	 	—	 	 	 	(73,995	)	
 	Mark to market of hedge contracts	 	 	41,271	 	 	 	4,335	 	 	 	(495	)	 	 	45,111	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Accumulated OCI balance at December 5, 2003	 	 	60,974	 	 	 	(4,476	)	 	 	(205	)	 	 	56,293	 	
 	Push down accounting adjustment	 	 	(60,974	)	 	 	4,476	 	 	 	205	 	 	 	(56,293	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Accumulated OCI balance at December 6, 2003	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
      During the period from January 1, 2003 to December 5, 2003, the Company reclassified losses of $32.0 million from OCI to current-period earnings as a result of the discontinuance of cash flow hedges due to liquidity problems at Loy Yang. These liquidity problems made it probable that the original forecasted transaction would not occur by the end of the originally specified time period. Additionally, gains of $74.0 million were reclassified from OCI to current period earnings during the period ended December 5, 2003, 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 period from January 1, 2003 to December 5, 2003, the Company recorded a gain in OCI of approximately $45.1 million related to changes in the fair values of derivatives accounted for as hedges. As of December 5, 2003, the Company made adjustments for push down accounting, resulting in a write-off of net gains recorded in OCI of $56.3 million.

28

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The following table summarizes the effects of SFAS No. 133 on the Company’s other comprehensive income balance at December 31, 2002:

 	 	Predecessor Company	

	
 	 	Energy	 	Interest	 	Foreign	 	 	
Gains (Losses)	 	Commodities	 	Rate	 	Currency	 	Total	

	 	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Accumulated OCI balance at December 31, 2001	 	$	87,736	 	 	$	(58,232	)	 	$	—	 	 	$	29,504	 	
 	Unwound from OCI during period	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Due to forecasted transactions probable of no longer occurring	 	 	—	 	 	 	8,611	 	 	 	—	 	 	 	8,611	 	
 	 	Due to termination of hedged items by counterparty	 	 	(6,130	)	 	 	—	 	 	 	—	 	 	 	(6,130	)	
 	 	Due to unwinding of previously deferred amounts	 	 	(29,490	)	 	 	14,248	 	 	 	—	 	 	 	(15,242	)	
 	Mark to market of hedge contracts	 	 	47,332	 	 	 	(11,213	)	 	 	290	 	 	 	36,409	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Accumulated OCI balance at December 31, 2002	 	$	99,448	 	 	$	(46,586	)	 	$	290	 	 	$	53,152	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
      During the year ended December 31, 2002, the Company reclassified losses of $8.6 million from OCI to current-period earnings as a result of the discontinuance of cash flow hedges because it is probable that the original forecasted transactions will not occur by the end of the originally specified time period. Also, gains of $6.1 million were reclassified from OCI to current period earnings due to the hedge items being terminated by the counterparties. Additionally, gains of $15.2 million were reclassified from OCI to current period earnings during the year ended December 31, 2002, 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 year ended December 31, 2002, the Company recorded a gain in OCI of approximately $36.4 million related to changes in the fair values of derivatives accounted for as hedges. The net balance in OCI relating to SFAS No. 133 at December 31, 2002, was an unrecognized gain of approximately $53.2 million.

 	Statement of Operations	
      The following tables summarize the effects of SFAS No. 133 on the Company’s consolidated statement of operations for the period from December 6, 2003 through December 31, 2003:

 	 	Reorganized Company	

	
 	 	Energy	 	Interest	 	 	
Gains (Losses)	 	Commodities	 	Rate	 	Total	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Revenue	 	$	(396	)	 	$	—	 	 	$	(396	)	
Cost of operations	 	 	—	 	 	 	—	 	 	 	—	 	
Equity in earnings of unconsolidated subsidiaries	 	 	(637	)	 	 	7	 	 	 	(630	)	
Interest expense	 	 	—	 	 	 	—	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
Total statement of operations impact before tax	 	$	(1,033	)	 	$	7	 	 	$	(1,026	)	

	 	 	 	

	 	 	 	

	 	
29

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The following tables summarize the effects of SFAS No. 133 on the Company’s consolidated statement of operations for the period from January 1, 2003 through December 5, 2003:

 	 	Predecessor Company	

	
 	 	Energy	 	Interest	 	 	
Gains (Losses)	 	Commodities	 	Rate	 	Total	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Revenue	 	$	—	 	 	$	—	 	 	$	—	 	
Cost of operations	 	 	8,586	 	 	 	—	 	 	 	8,586	 	
Equity in earnings of unconsolidated subsidiaries	 	 	4,059	 	 	 	14,963	 	 	 	19,022	 	
Interest expense	 	 	—	 	 	 	—	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
Total statement of operations impact before tax	 	$	12,645	 	 	$	14,963	 	 	$	27,608	 	

	 	 	 	

	 	 	 	

	 	
      The following tables summarize the effects of SFAS No. 133 on the Company’s consolidated statement of operations for the year ended December 31, 2002:

 	 	Predecessor Company	

	
 	 	Energy	 	Interest	 	 	
Gains (Losses)	 	Commodities	 	Rate	 	Total	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Revenue	 	$	—	 	 	$	—	 	 	$	—	 	
Cost of operations	 	 	(6,891	)	 	 	—	 	 	 	(6,891	)	
Equity in earnings of unconsolidated subsidiaries	 	 	(1,426	)	 	 	(970	)	 	 	(2,396	)	
Interest expense	 	 	—	 	 	 	—	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	
Total statement of operations impact before tax	 	$	(8,317	)	 	$	(970	)	 	$	(9,287	)	

	 	 	 	

	 	 	 	

	 	
      The following table summarizes the effects of SFAS No. 133 on the Company’s consolidated statement of operations for the year ended December 31, 2001:

 	 	Predecessor Company	

	
 	 	Energy	 	Interest	 	 	
Gains (Losses)	 	Commodities	 	Rate	 	Total	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Revenue	 	$	—	 	 	$	—	 	 	$	—	 	
Cost of operations	 	 	(2,644	)	 	 	—	 	 	 	(2,644	)	
Other income	 	 	—	 	 	 	—	 	 	 	—	 	
Equity in earnings of unconsolidated subsidiaries	 	 	5,467	 	 	 	(805	)	 	 	4,662	 	

	 	 	 	

	 	 	 	

	 	
Total statement of operations impact before tax	 	$	2,823	 	 	$	(805	)	 	$	2,018	 	

	 	 	 	

	 	 	 	

	 	

 	Energy Related Commodities	
      The Company is exposed to commodity price variability in electricity and natural gas, oil and coal used to meet fuel requirements. In order to manage these commodity price risks, the Company enters into financial instruments, which may take the form of fixed price, floating price or indexed sales or purchases, and options, such as puts, calls, basis transactions and swaps. Certain of these transactions have been designated as cash flow hedges. The Company has accounted for these derivatives by recording the effective portion of the cumulative gain or loss on the derivative instrument as a component of OCI in member’s equity. The Company recognizes deferred gains and losses into earnings in the same period or periods during which the hedged transaction affects earnings. Such reclassifications are included on the same line of the consolidated statement of operations in which the hedged item is recorded.

30

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      No ineffectiveness was recognized on commodity cash flow hedges during the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003, and for the years ended December 31, 2002 and 2001.

      The Company’s pre-tax earnings for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003, and for the years ended December 31, 2002 and 2001, were affected by an unrealized loss of $1.0 million, an unrealized gain of $12.6 million, an unrealized loss of $8.3 million and an unrealized gain of $2.8 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.

      During the period from December 6, 2003 to December 31, 2003 and the period from January 1, 2003 to December 5, 2003, gains of $0 and $79.7 million, respectively, were reclassified from OCI to current-period earnings. During the year ended December 31, 2002, the Company reclassified gains of $35.6 million from OCI to current-period earnings. As of December 5, 2003, the Company made adjustments for the application of push down accounting. These push down accounting adjustments resulted in a write-off of net gains recorded in OCI of $61 million on energy related derivative instruments accounted for as hedges. The Company expects to reclassify an additional $1.0 million of deferred losses to earnings during the next twelve months on energy related derivative instruments accounted for as hedges.

 	Interest Rates	
      To manage interest rate risk, the Company has entered into interest-rate swaps that effectively fix the interest payments of certain floating rate debt instruments. Interest-rate swap agreements are accounted for as cash flow hedges. The effective portion of the cumulative gain or loss on the derivative instrument is reported as a component of OCI in member’s equity and recognized into earnings as the underlying interest expense is incurred. Such reclassifications are included on the same line of the consolidated statement of operations in which the hedged item is recorded.

      No ineffectiveness was recognized on interest rate cash flow hedges during the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003, or for the years ended December 31, 2002 and 2001.

      The Company’s pre-tax earnings for the period from December 6, 2003 to December 31, 2003 and for the period from January 1, 2003 through December 5, 2003, were affected by an unrealized gain of $0 and $14.9 million, respectively, associated with changes in the fair value of interest rate derivative instruments not accounted for as hedges in accordance with SFAS No. 133.

      The Company’s pre-tax earnings for the years ended December 31, 2002 and 2001, were decreased by an unrealized loss of $1.0 million and $0.8 million, respectively, associated with changes in the fair value of interest rate derivative instruments not accounted for as hedges in accordance with SFAS No. 133.

      During the period from December 6, 2003 to December 31, 2003 and the period from January 1, 2003 to December 5, 2003, losses of $0 and $37.8 million, respectively, were reclassified from OCI to current-period earnings. During the year ended December 31, 2002, the Company reclassified losses of $22.9 million from OCI to current-period earnings. As of December 5, 2003, the Company made adjustments for the application of push down accounting. These push down accounting adjustments resulted in a write-off of net losses recorded in OCI of $4.5 million on interest rate swaps accounted for as hedges. The Company expects to reclassify an additional $0.1 million of deferred losses to earnings during the next twelve months on interest rate swaps accounted for as hedges.

31

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

13.	Long-Term Debt and Capital Leases	
      Long-term debt and capital leases consist of the following:

 	 	 	 	 	 	Reorganized Company	 	 	

	 	Predecessor	
 	 	 	 	 	 	 	 	 	 	Company	
 	 	 	 	 	 	December 31, 2003	 	December 6, 2003	 	

	

	 	

	 	December 31,	
 	 	Stated	 	Effective	 	 	 	Fair Value	 	 	 	Fair Value	 	2002	
 	 	Rate	 	Rate	 	Principal	 	Adjustment	 	Principal	 	Adjustment	 	Principal	

	 	

	 	

	 	

	 	

	 	

	 	

	
 	 	 	 	 	
 	 	Percent	 	(In thousands of dollars)	
Flinders Power Partnership September 2012	 	 	(1	)	 	 	6	%	 	$	187,668	 	 	$	10,632	 	 	$	185,825	 	 	$	10,434	 	 	$	98,276	 	
NRG International Inc.	 	 	—	 	 	 	(2	)	 	 	10,664	 	 	 	—	 	 	 	10,664	 	 	 	—	 	 	 	35,051	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	Long-term debt affiliates	 	 	 	 	 	 	 	 	 	 	198,332	 	 	 	10,632	 	 	 	196,489	 	 	 	10,434	 	 	 	133,327	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Saale Energie GmbH, Schkopau capital lease, due 2021	 	 	—	 	 	 	(3	)	 	 	342,470	 	 	 	—	 	 	 	318,359	 	 	 	—	 	 	 	333,929	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	Long-term debt nonaffiliates	 	 	 	 	 	 	 	 	 	 	342,470	 	 	 	—	 	 	 	318,359	 	 	 	—	 	 	 	333,929	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	 	 	 	 	 	 	 	 	540,802	 	 	 	10,632	 	 	 	514,848	 	 	 	10,434	 	 	 	467,256	 	
Less: Current maturities	 	 	 	 	 	 	 	 	 	 	86,608	 	 	 	—	 	 	 	72,137	 	 	 	—	 	 	 	61,560	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	 	 	 	 	 	 	 	$	454,194	 	 	$	10,632	 	 	$	442,711	 	 	$	10,434	 	 	$	405,696	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	

 	 	
(1) 	Rates range from 2.93% to 6.34%.	
 	 	
(2) 	Non-interest bearing debt.	
 	 	
(3) 	Effective rate of capital lease was 12.7% for the Predecessor Company and 11% for the Reorganized Company.	
      At December 31, 2003, the Company has timely made scheduled payments on interest and/or principal on all of its debt and was not in default under any of the Company’s debt instruments.

      In December 2003, the Company entered into a note payable in the amount of $10.7 million with NRGenerating Holdings No. 21 BV, an indirect wholly owned subsidiary of NRG Energy and an affiliate of the Company, in connection with the sale of the Company’s 100% ownership interest in Sterling Luxembourg (No. 4) S.a.r.L. (see Note 21 — Related Party Transactions). The note is payable on demand.

Project Financings

 	Flinders Power	
      In September 2000, Flinders Power Finance Pty Ltd (“Flinders Finance”) an indirect wholly owned subsidiary of NRG Energy and an affiliate of the Company, entered into a twelve-year AUD$150 million cash advance facility (US$81.4 million at September 2000). At December 31, 2003, December 6, 2003 and December 31, 2002, there remains AUD$135.0 million (US$101.6 million), AUD$135.0 million (US$99.3 million) and AUD$143.4 million (US$80.5 million) outstanding under this facility, respectively. The interest has a fixed margin and variable base component. At December 31, 2003, December 6, 2003 and

32

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

December 31, 2002, the interest rate was 7.53%, 7.53% and 6.49%, respectively, and is paid semi-annually. Principal payments commence in 2006 and the facility will be fully paid in 2012.

      In March 2002, Flinders Finance entered into a 10-year AUD$165 million (US$85.4 million at March 2002) floating rate loan facility for the purpose of refurbishing the Flinders Playford generating station. As of December 31, 2003, December 6, 2003 and December 31, 2002, the Company had drawn AUD$114.3 million (US$86.0 million), AUD$114.3 million (US$86.5 million) and AUD$33.3 million (US$18.7 million), respectively, of this facility. The interest rate has a fixed margin and variable base component. The interest rate at December 31, 2003, December 6, 2003 and December 31, 2002, was 7.03%, 7.03% and 6.14%, respectively, and is paid semi-annually. Principal payments for the refurbishment facility commence in 2005. Upon the Company’s downgrades in 2002, there existed a potential default under these facility agreements related to the funding of reserve accounts. On May 13, 2003, Flinders Finance and its lenders entered into a Second Supplemental Deed, which resolved these potential defaults. As part of the terms of that Second Supplemental Deed, part of the refurbishment facility was voluntarily cancelled by Flinders Finance so as to reduce the total available commitment from AUD$165 million to AUD$137 million (US$103.1 million).

      In addition, Flinders Finance has an AUD$20 million (US$15 million) working capital facility, of which AUD$11.2 million (US$8.2 million) is reserved as support for potential calls on performance guarantees. Nothing has been drawn under this facility at December 31, 2003, December 6, 2003 and December 31, 2002.

      All drawn funds under the above mentioned facilities and bank loans are lent to Flinders Power by Flinders Finance through project loan agreements. The terms and conditions are identical to the agreements with the third parties.

 	Saale Energie GmbH	
      In connection with the purchase of PowerGen’s (third party owner) interest in Saale Energie GmbH (“SEG”), which then became a subsidiary of the Company, SEG entered into two agreements which qualify to be treated as capital lease agreements (a) the “Agreement on the Surrender of the Use and Benefit” (“U&B”) between SEG and Kraftwerke Schkopau GbR (“Schkopau”) and (b) the Power Supply Contract (“PPA”) between SEG and Vattenfall Europe A.G. (“VEAG”). Both contracts transfer substantially all of the benefits and risks of ownership of the share in the power plant from Schkopau to SEG and finally to VEAG. The power supply contract is not simply a service contract, but rather a lease contract, because SEG sells 100% of the capacity in its share of the power plant over 25 years (which is more than 83% of the useful life of the power plant) to VEAG. The U&B contract is accounted for as a long-term lease obligation in the consolidated financial statements. The PPA is accounted for as a direct financing lease with a note receivable in the consolidated financial statements. The Company has recognized a nonrecourse capital lease on the consolidated balance sheet in the amount of $342.5 million, $318.4 million and $333.9 million at December 31, 2003, December 6, 2003 and December 31, 2002, respectively. The capital lease obligation is recorded at the net present value of the minimum lease obligation payable over the lease’s remaining period of 19 years. In addition, a direct financing lease was recorded in notes receivable in the amount of approximately $451.4 million, $435.0 million and $366.4 million as of December 31, 2003, December 6, 2003 and December 31, 2002, respectively.

33

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      Annual maturities of long-term debt and capital leases for the years ending after December 31, 2003, are as follows:
 	 	 	 	 	
 	 	(In thousands of dollars)	
2004	 	$	86,608	 	
2005	 	 	87,872	 	
2006	 	 	56,294	 	
2007	 	 	46,613	 	
2008	 	 	41,776	 	
Thereafter	 	 	221,639	 	

	 	
 	 	$	540,802	 	

	 	
      Future minimum lease payments for capital leases included above at December 31, 2003, are as follows:
 	 	 	 	 	
 	 	(In thousands of dollars)	
2004	 	$	100,675	 	
2005	 	 	103,615	 	
2006	 	 	65,882	 	
2007	 	 	52,654	 	
2008	 	 	44,947	 	
Thereafter	 	 	233,298	 	

	 	
Total minimum obligations	 	 	601,071	 	
Interest	 	 	258,601	 	

	 	
Present value of minimum obligations	 	 	342,470	 	
Current portion	 	 	75,944	 	

	 	
Long-term obligations	 	$	266,526	 	

	 	

14.	Financial Instruments	
      The estimated fair values of the Company’s recorded financial instruments are as follows:

 	 	Reorganized Company	 	Predecessor Company	

	 	

	
 	 	 	 	 	 	 	
 	 	December 31, 2003	 	December 6, 2003	 	December 31, 2002	

	 	

	 	

	
 	 	Carrying	 	Fair	 	Carrying	 	Fair	 	Carrying	 	Fair	
 	 	Amount	 	Value	 	Amount	 	Value	 	Amount	 	Value	

	 	

	 	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Cash and cash equivalents	 	$	127,020	 	 	$	127,020	 	 	$	125,914	 	 	$	125,914	 	 	$	192,862	 	 	$	192,862	 	
Restricted cash	 	 	45,874	 	 	 	45,874	 	 	 	44,802	 	 	 	44,802	 	 	 	17,214	 	 	 	17,214	 	
Notes receivable, including current portion	 	 	620,685	 	 	 	620,685	 	 	 	599,780	 	 	 	599,780	 	 	 	565,649	 	 	 	565,649	 	
Long-term debt and capital leases, including current portion	 	 	551,434	 	 	 	551,434	 	 	 	525,282	 	 	 	525,282	 	 	 	467,256	 	 	 	467,256	 	
      For cash and cash equivalents and restricted cash, the carrying amount approximates fair value because of the short-term maturity of those instruments. The fair value of notes receivable is based on expected future cash flows discounted at market interest rates. The fair value of long-term debt is estimated based on a present value method using current interest rates for similar instruments with equivalent credit quality.

34

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

15.	Segment Reporting	
      The Company conducts its business within two reportable operating segments — Power Generation Australia and Power Generation — Europe. These reportable segments are distinct components with separate operating results and management structures in place.

      For the period from December 6, 2003 to December 31, 2003:

 	 	Reorganized Company	
 	 	Power Generation	

	
 	 	Australia	 	Europe	 	Total	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Operations	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues	 	$	24,733	 	 	$	(1,375	)	 	$	23,358	 	
Operating costs	 	 	22,658	 	 	 	(3,904	)	 	 	18,754	 	
Depreciation and amortization	 	 	1,480	 	 	 	(5	)	 	 	1,475	 	
General and administrative expenses	 	 	297	 	 	 	696	 	 	 	993	 	
Other expense (income)	 	 	1,359	 	 	 	(1,798	)	 	 	(439	)	
Equity in earnings in unconsolidated affiliates	 	 	997	 	 	 	710	 	 	 	1,707	 	
Income tax (benefit) expense	 	 	(267	)	 	 	1,063	 	 	 	796	 	
Net income from continuing operations	 	 	203	 	 	 	3,283	 	 	 	3,486	 	
Net loss from discontinued operations	 	 	—	 	 	 	(222	)	 	 	(222	)	
Net income	 	 	203	 	 	 	3,061	 	 	 	3,264	 	
 	
Balance sheet	 	 	 	 	 	 	 	 	 	 	 	 	
Investment in projects	 	 	136,129	 	 	 	196,488	 	 	 	332,617	 	
Total assets	 	 	1,054,301	 	 	 	722,724	 	 	 	1,777,025	 	
35

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      For the period from January 1, 2003 to December 5, 2003:

 	 	Predecessor Company	
 	 	Power Generation	

	
 	 	Australia	 	Europe	 	Total	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Operations	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues	 	$	152,841	 	 	$	118,824	 	 	$	271,665	 	
Operating costs	 	 	110,271	 	 	 	102,646	 	 	 	212,917	 	
Depreciation and amortization	 	 	15,708	 	 	 	139	 	 	 	15,847	 	
General and administrative expenses	 	 	3,725	 	 	 	5,553	 	 	 	9,278	 	
Restructuring and impairment charges	 	 	—	 	 	 	3,929	 	 	 	3,929	 	
Other expense (income)	 	 	17,282	 	 	 	(10,704	)	 	 	6,578	 	
Equity in earnings in unconsolidated affiliates	 	 	30,364	 	 	 	31,536	 	 	 	61,900	 	
Write downs and gains (losses) on sales of equity method investments	 	 	(146,354	)	 	 	7,983	 	 	 	(138,371	)	
Income tax expense (benefit)	 	 	(240	)	 	 	11,603	 	 	 	11,363	 	
Net (loss) income from continuing operations	 	 	(109,895	)	 	 	45,177	 	 	 	(64,718	)	
Net income from discontinued operations	 	 	—	 	 	 	169,183	 	 	 	169,183	 	
Net (loss) income	 	 	(109,895	)	 	 	214,360	 	 	 	104,465	 	
 	
Balance sheet	 	 	 	 	 	 	 	 	 	 	 	 	
Investment in projects	 	 	131,864	 	 	 	194,934	 	 	 	326,798	 	
Total assets	 	 	693,752	 	 	 	1,044,295	 	 	 	1,738,047	 	
36

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      For the year ended December 31, 2002:

 	 	Predecessor Company	
 	 	Power Generation	

	
 	 	Australia	 	Europe	 	Total	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Operations	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues	 	$	172,547	 	 	$	107,203	 	 	$	279,750	 	
Operating costs	 	 	155,270	 	 	 	81,108	 	 	 	236,378	 	
Depreciation and amortization	 	 	14,794	 	 	 	206	 	 	 	15,000	 	
General and administrative expenses	 	 	2,360	 	 	 	7,464	 	 	 	9,824	 	
Restructuring and impairment charges	 	 	13,382	 	 	 	40,119	 	 	 	53,501	 	
Other expense (income)	 	 	12,536	 	 	 	(13,006	)	 	 	(470	)	
Equity in earnings in unconsolidated affiliates	 	 	8,692	 	 	 	40,605	 	 	 	49,297	 	
Write downs and losses on sales of equity method investment	 	 	(139,146	)	 	 	—	 	 	 	(139,146	)	
Income tax (benefit) expense	 	 	(2,885	)	 	 	16,628	 	 	 	13,743	 	
Net gain/(loss) from continuing operations	 	 	(153,364	)	 	 	15,289	 	 	 	(138,075	)	
Net loss from discontinued operations	 	 	—	 	 	 	(553,008	)	 	 	(553,008	)	
Net loss	 	 	(153,364	)	 	 	(537,719	)	 	 	(691,083	)	
 	
Balance sheet	 	 	 	 	 	 	 	 	 	 	 	 	
Investment in projects	 	 	67,299	 	 	 	242,449	 	 	 	309,748	 	
Total assets	 	 	482,478	 	 	 	1,652,139	 	 	 	2,134,617	 	
      For the year ended December 31, 2001:

 	 	Predecessor Company	
 	 	Power Generation	

	
 	 	Australia	 	Europe	 	Total	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Operations	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues	 	$	214,817	 	 	$	70,305	 	 	$	285,122	 	
Operating costs	 	 	181,459	 	 	 	53,559	 	 	 	235,018	 	
Depreciation and amortization	 	 	14,535	 	 	 	239	 	 	 	14,774	 	
General and administrative expenses	 	 	1,573	 	 	 	12,828	 	 	 	14,401	 	
Other expense (income)	 	 	14,305	 	 	 	(12,548	)	 	 	1,757	 	
Equity in earnings in unconsolidated affiliates	 	 	8,500	 	 	 	48,422	 	 	 	56,922	 	
Income tax expense	 	 	6,354	 	 	 	9,686	 	 	 	16,040	 	
Net income from continuing operations	 	 	5,091	 	 	 	54,963	 	 	 	60,054	 	
Net income from discontinued operations	 	 	—	 	 	 	40,276	 	 	 	40,276	 	
Net income	 	 	5,091	 	 	 	95,239	 	 	 	100,330	 	

16.	Income Taxes	
      Segments of the Company are included in the consolidated tax return filings as a wholly owned direct held subsidiary of NRG Energy. Reflected in the financial statements and notes below are separate company federal, state and international tax provisions as if the Company had prepared separate filings. An income tax provision has been established on the accompanying financial statements as of the earliest period presented in

37

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

order to reflect income taxes as if the Company filed its own tax return. The Company’s parent, NRG Energy, does not have a tax allocation agreement with its subsidiaries nor has it historically pushed down or allocated income taxes to non tax paying entities or entities such as the Company which are treated as disregarded entities for tax purposes. The Company operates in various international jurisdictions through its subsidiaries and affiliates and incurs income tax liabilities (assets) under the applicable tax laws and regulations. Because the Company is not a party to a tax sharing agreement, current tax expense (benefit) is recorded as a capital contribution from (distribution to) the Company’s parent. The cumulative effect of recording an income tax provision (benefit) and deferred taxes resulted in recording as of December 31, 2000, a net deferred tax liability of $26.5 million and a reduction to members’ equity of $26.5 million.

      The provision (benefit) for income taxes consists of the following:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the Period	 	For the Period	 	 	
 	 	from	 	from	 	For the Years Ended	
 	 	December 6, 2003	 	January 1, 2003	 	December 31,	
 	 	to	 	to	 	

	
 	 	December 31, 2003	 	December 5, 2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Current	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	U.S. — Federal	 	$	—	 	 	$	—	 	 	$	250	 	 	$	1,748	 	
 	Foreign	 	 	1,283	 	 	 	10,985	 	 	 	12,227	 	 	 	5,332	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	1,283	 	 	 	10,985	 	 	 	12,477	 	 	 	7,080	 	
Deferred	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	U.S. — Federal	 	 	—	 	 	 	—	 	 	 	1,016	 	 	 	—	 	
 	Foreign	 	 	(487	)	 	 	378	 	 	 	250	 	 	 	8,960	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	 	(487	)	 	 	378	 	 	 	1,266	 	 	 	8,960	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Total income tax (benefit) expense	 	$	796	 	 	$	11,363	 	 	$	13,743	 	 	$	16,040	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
      The pre-tax income (loss) between U.S. and foreign was as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the Period	 	For the Period	 	 	
 	 	from	 	from	 	For the Years Ended	
 	 	December 6, 2003	 	January 1, 2003	 	December 31,	
 	 	to	 	to	 	

	
 	 	December 31, 2003	 	December 5, 2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
U.S. 	 	$	28	 	 	$	(2,597	)	 	$	(284	)	 	$	2,804	 	
Foreign	 	 	4,254	 	 	 	(50,758	)	 	 	(124,048	)	 	 	73,290	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	$	4,282	 	 	$	(53,355	)	 	$	(124,332	)	 	$	76,094	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
38

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The components of the net deferred income tax liabilities were:

 	 	Reorganized Company	 	Predecessor Company	

	 	

	
 	 	 	 	 	 	 	
 	 	December 31, 2003	 	December 6, 2003	 	December 31, 2002	

	 	

	 	

	
 	 	U.S.	 	Foreign	 	U.S.	 	Foreign	 	U.S.	 	Foreign	

	 	

	 	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Deferred tax liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Difference between book and tax basis of property	 	$	—	 	 	$	361,888	 	 	$	—	 	 	$	355,768	 	 	$	—	 	 	$	240,907	 	
 	Net unrealized gains on mark to market transactions	 	 	—	 	 	 	13,215	 	 	 	—	 	 	 	14,868	 	 	 	—	 	 	 	9,301	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total deferred tax liabilities	 	 	—	 	 	 	375,103	 	 	 	—	 	 	 	370,636	 	 	 	—	 	 	 	250,208	 	
Deferred tax assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Difference between book and tax basis of contracts	 	 	—	 	 	 	24,717	 	 	 	—	 	 	 	23,471	 	 	 	—	 	 	 	19,806	 	
 	Tax loss carryforwards	 	 	2,648	 	 	 	337,614	 	 	 	2,640	 	 	 	337,614	 	 	 	1,453	 	 	 	231,668	 	
 	Investments in projects	 	 	1,487	 	 	 	—	 	 	 	1,487	 	 	 	—	 	 	 	580	 	 	 	—	 	
 	Other	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	654	 	 	 	—	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	 	Total deferred tax assets (before valuation allowance)	 	 	4,135	 	 	 	362,331	 	 	 	4,127	 	 	 	361,085	 	 	 	2,687	 	 	 	251,474	 	
Valuation allowance	 	 	(4,135	)	 	 	(152,357	)	 	 	(4,127	)	 	 	(152,357	)	 	 	(2,687	)	 	 	(112,075	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Net deferred tax assets	 	 	—	 	 	 	209,974	 	 	 	—	 	 	 	208,728	 	 	 	—	 	 	 	139,399	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Net deferred tax liabilities	 	$	—	 	 	$	165,129	 	 	$	—	 	 	$	161,908	 	 	$	—	 	 	$	110,809	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
      The net deferred tax liabilities (assets) consists of:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Predecessor	
 	 	Reorganized Company	 	Company	

	 	

	
 	 	December 31, 2003	 	December 6, 2003	 	December 31, 2002	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Current deferred tax liabilities (assets)	 	$	(754	)	 	$	—	 	 	$	—	 	
Noncurrent deferred tax liabilities (assets)	 	 	165,883	 	 	 	161,908	 	 	 	110,809	 	

	 	 	 	

	 	 	 	

	 	
Net deferred tax liabilities (assets)	 	$	165,129	 	 	$	161,908	 	 	$	110,809	 	

	 	 	 	

	 	 	 	

	 	
      As of December 31, 2003 the Company had net operating losses related to Australia ($724.4 million), Netherlands ($348.7 million), and the U.S. ($6.4 million). The tax effected foreign loss carryforwards recorded related to these gross net operating losses were Australia ($217.3 million), Netherlands ($120.3 million), and the U.S. ($2.6 million). The carryforward net operating losses have an indefinite life except for the U.S. portion which will expire in 20 years.

      Management assesses the need for a valuation allowance based on SFAS No. 109 criteria that deferred tax assets must be reduced by a valuation allowance if, based on the weight of available evidence it is more likely than not that some portion or all of the deferred tax assets will not be realized. Given the Company’s history of operating losses, it is management’s assessment that deferred tax assets have been reduced to the amount that is more likely than not to be realized by the establishment of the valuation allowance. As of December 31, 2003 a significant portion of the valuation allowance related to the Loy Yang Project which was sold in April 2004. This project had net deferred tax assets of $150.1 million related to net operating losses that

39

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

were fully reserved for. The Loy Yang Project’s valuation allowance was split between the following jurisdictions: Netherlands ($95.8 million) and Australia ($54.2 million).

      The fluctuations in the valuation allowance between the periods shown above was primarily due to the change in the Loy Yang’s Project’s deferred tax assets.

      The effective income tax rates of continuing operations differ from the statutory federal income tax rate of 35% as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	 	 	 	 	
 	 	Company	 	 	 	Predecessor Company	 	 	

	 	 	 	

	 	 	
 	 	For the	 	 	 	For the	 	 	 	 	
 	 	Period from	 	 	 	Period from	 	 	 	 	
 	 	December 6,	 	 	 	January 1,	 	 	 	 	 	 	
 	 	2003 to	 	 	 	2003 to	 	 	 	For the Years Ended December 31,	 	 	
 	 	December 31,	 	 	 	December 5,	 	 	 	

	 	 	
 	 	2003	 	 	 	2003	 	 	 	2002	 	 	 	2001	 	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	 	
 	 	 	 	 	
 	 	(In thousands of dollars)	 	 	
Income (loss) before taxes	 	$	4,282	 	 	 	 	 	 	$	(53,355	)	 	 	 	 	 	$	(124,332	)	 	 	 	 	 	$	76,094	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	
Tax at 35%	 	 	1,498	 	 	 	35.0	%	 	 	(18,674	)	 	 	35.0	%	 	 	(43,517	)	 	 	35.0	%	 	 	26,633	 	 	 	35.0	%	
State taxes (net of federal benefit)	 	 	—	 	 	 	0.0	%	 	 	—	 	 	 	0.0	%	 	 	(41	)	 	 	0.0	%	 	 	227	 	 	 	0.3	%	
Foreign tax	 	 	(583	)	 	 	(13.6	)%	 	 	29,758	 	 	 	(55.8	)%	 	 	54,007	 	 	 	(43.4	)%	 	 	(11,550	)	 	 	(15.2	)%	
Other	 	 	(119	)	 	 	(2.8	)%	 	 	279	 	 	 	(0.5	)%	 	 	3,294	 	 	 	(2.7	)%	 	 	730	 	 	 	1.0	%	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	
Income tax expense	 	$	796	 	 	 	18.6	%	 	$	11,363	 	 	 	(21.3	)%	 	$	13,743	 	 	 	(11.1	)%	 	$	16,040	 	 	 	21.1	%	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	

	 	 	 	 	 	
      At December 31, 2003, NRG Energy’s management intends to indefinitely reinvest the earnings from its foreign operations. Accordingly, U.S. income taxes and foreign withholding taxes were not provided on the earnings from the foreign subsidiaries. For the periods ending December 31, 2003, December 5, 2003 and December 31, 2002, no U.S. income tax benefit was provided on the cumulative amount of losses from the Company of $387.5 million, $438.4 million and $341.7 million, respectively. At December 31, 2001, the Company had not provided U.S. income taxes and foreign withholding taxes on $345.0 million of cumulative earnings from the foreign subsidiaries.

17.	Benefit Plans and Other Postretirement Benefits	

 	Flinders Power Retirement Plan	
      Employees of Flinders Power, a wholly owned subsidiary of the Company, are members of the multiemployer Electricity Industry Superannuation Schemes, (“EISS”) Members of the EISS make contributions from their salary and the EISS Actuary makes an assessment of the Company’s liability. As a result of the adoption of Push Down accounting, the Company recorded a liability of approximately $13.8 million at December 6, 2003, to record its accumulated benefit obligation plan assets on the consolidated balance sheet at fair value. The consolidated balance sheet includes a liability related to the Flinders retirement plan of $13.7 million, $13.8 million and $12.3 million at December 31, 2003, December 6, 2003 and December 31, 2002, respectively. Flinders Power made contributions of $0, $4.5 million and $5.8 million for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003, and for the year ended December 31, 2002, respectively.

      The Superannuation Board is responsible for the investment of Scheme assets. The assets may be invested in government securities, shares, property and a variety of other securities and the Board may appoint professional investment managers to invest all or part of the assets on its behalf.

40

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

18.	Commitments and Contingencies	

 	Operating Lease Commitments	
      The Company leases certain of its facilities and equipment under operating leases, some of which include escalation clauses, expiring on various dates through 2008. Rental expense under these operating leases was $0 for the period from December 6, 2003 to December 31, 2003, $0.5 million for the period from January 1, 2003 to December 5, 2003, and $0 for the years ended December 31, 2002 and 2001, respectively. Future minimum lease commitments under these leases for the years ending after December 31, 2003, are as follows:
 	 	 	 	 	
 	 	(In thousands of dollars)	
2004	 	$	1,258	 	
2005	 	 	1,213	 	
2006	 	 	1,019	 	
2007	 	 	891	 	
2008	 	 	365	 	
Thereafter	 	 	—	 	

	 	
 	 	$	4,746	 	

	 	
Legal Issues

 	Matra Powerplant Holding B.V.	
      Matra Powerplant Holding B.V. (“Matra”) is presently involved in a dispute with the Dutch tax commissioner. For the tax years from 1998 until 2001, NRGenerating International B.V. indirectly (through Kladno Power (No. 2) B.V. and Entrade Holdings B.V.) held 50% of the issued and outstanding shares in the capital of Matra. The shareholders of Matra granted interest-free loans to Matra in reliance upon a favorable tax ruling granted to NRGenerating International B.V. in 1994.

      The tax commissioner now has asserted that the loans constitute capital contributions (so-called shareholders’ loans) and thereby has challenged the imputed interest deductions of Matra in the subsequent years.

      Accordingly, the tax commissioner has issued the following statutory notices of deficiency (“SND”) and tax assessments (“TA”):
 	 	 	 	 	 	 	 	 	
1998 SND	 	Corporate Income Tax 35%	 	USD	 	$	496,510	 	
1998 SND	 	Capital Duty 1%	 	EUR	 	 	279,156	 	
2001 TA	 	Corporate Income Tax 35%	 	USD	 	$	1,451,088	 	
      The Company has filed appeals against the SND and TA. For the 1998 corporate income tax SND, the tax commissioner has to prove that a new fact justifies the SND. This is not required for the 1998 capital duty SND or the 2001 corporate income TA. At this time, the Company cannot estimate the likelihood of success regarding these claims.

 	Threatened claims against the Company’s subsidiaries relating to the funding of several projects, realized by way of (informal) capitalization	
      The Dutch tax commissioner has asserted that the capitalization of some of the Company’s subsidiaries was basically intended to avoid capital duty in The Netherlands, which could constitute abuse of law (“fraus legis”). In the Company’s correspondence with the tax commissioner, the Company made clear that there were other substantial commercial reasons to use these specific structures, including avoidance of currency exchange gains and/or capital duty in Luxembourg and/or other reasons.

41

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The tax commissioner has not yet responded to the Company’s latest response sent to the commission on May 21, 2001.

      The threatened respective amounts of capital duty are:
 	 	
 	      (a) NRGenerating International B.V.: AUD$1,569,366 and AUD$3,784,670, UK pounds 1,080,000 and UK pounds 155,294;	
 	 	
 	      (b) NRGenerating Holdings (No. 15) B.V.: UK pounds 900,000; and	
 	 	
 	      (c) NRGenerating Holdings (No. 20) B.V.: US$1.	
      No prediction of the likelihood of an unfavorable outcome can be made at this time.

 	NRGenerating Holdings (No. 4) B.V. and Gunwale B.V.	
      In the years 1999 and 2000, Gunwale B.V. was part of a transaction intended to recapitalize NRGenerating Holdings (No. 4) B.V. The Company has asserted that these transactions were structured so as to mitigate currency exchange risk and for other substantial commercial reasons. The tax commissioner has issued statutory notices of deficiency for both NRGenerating Holdings (No. 4) B.V. and Gunwale B.V., arguing that asserted exemptions do not apply and that duty should have been paid under prevailing law. The threatened amount of capital duty due would amount to approximately EUR 235,943 for the year 1999 and EUR 1,325,334 for the year 2000.

      Objections to these notices have been filed by Dutch counsel for the buyer, Grant Energy Alliance Corporation, of NRGenerating Holdings (No. 4) B.V. and Gunwale B.V.

      Although both companies were sold in April 2004 as part of the sale of Loy Yang, and therefore are no longer held by any of the Company’s affiliates, under the share sale agreement, the Company still could become indirectly liable for the subject capital duty, should the buyer exercise a put-option for a predetermined price respective to the shares in Gunwale B.V.

 	Matra Powerplant Holding B.V.	
      The Dutch tax commissioner appears to have treated Matra’s taxable income for 1999 in a manner inconsistent with the commissioner’s treatment of Matra’s taxable income for 1998 and 2001, as referenced above. In the event the commissioner were to later assert that it clearly erred in its 1999 treatment, the commissioner could issue a new SND, subject to demonstrating that the taxpayer should have been aware of this error and the existence of a new fact to support the new SND. Should the tax commissioner issue a new SND for 1999, the Company believes the assessment could exceed US$1.2 million.

Contractual Commitments

 	Flinders Power	
      Upon the acquisition of Flinders Power in August 2000, the South Australian Government assigned money losing contracts with Osborne Power Plant (“OCPL”) to Flinders Power. The Osborne plant has a nameplate capacity of 180 MW, notionally comprising baseload capacity of 134 MW, surplus baseload capacity of 7 MW and peaking capacity of 39 MW. Under its power purchase agreement with the owner of the OCPL, Flinders Power purchases electricity from OCPL and bids that electricity into the National Electricity Market (“NEM”). Under a separate gas sale agreement, Flinders Power also supplies OCPL with gas. Flinders Power is supplied with that gas under a contract with Terra Gas Trader (“TGT”). These contracts are derivatives that do not qualify for hedge accounting treatment in accordance with SFAS No. 133. See Note 12 — Derivative Instruments and Hedging Activities.

42

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      TGT is owned by Tarong Energy (a Queensland Government owned corporation). Both Flinders Power’s purchases of electricity from OCPL and supply of gas to OCPL are at a loss. These contracts are accounted for as derivatives and reflected accordingly in the consolidated financial statements of the Company.

19.	Guarantees	
      In November 2002, the FASB issued FASB Interpretation No. (“FIN”) 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others . The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor’s fiscal year end. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002. The interpretation addresses the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees. The interpretation also clarifies the requirements related to the recognition of a liability by a guarantor at the inception of the guarantee for the obligations the guarantor has undertaken in issuing the guarantee.

      In connection with the application of push down accounting, all outstanding guarantees were considered new; accordingly, the Company applied the provisions of FIN 45 to all of those guarantees. Each guarantee was reviewed for the requirement to recognize a liability at inception. As a result, the Company was not required to record any liabilities.

      On December 23, 2003, the Company’s parent, NRG Energy, issued $1.25 billion of 8% Second Priority Notes, due and payable on December 15, 2013. On January 28, 2004, NRG Energy also issued $475.0 million of Second Priority Notes, under the same terms and indenture as its December 23, 2003 offering.

      NRG Energy’s payment obligations under the notes and all related Parity Lien Obligations are guarantees on an unconditional basis by each of NRG Energy’s current and future restricted subsidiaries, of which the Company is one. The notes are jointly and severally guaranteed by each of the guarantors. The subsidiary guarantees of the notes are secured, on a second priority basis, equally and ratably with any future parity lien debt, by security interest in all of the assets of the guarantors, except certain excluded assets, subject to liens securing parity lien debt and other permitted prior liens.

      The Company’s obligations pursuant to its guarantees of the performance, equity and indebtedness obligations were as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantee/	 	 	 	 	 	 	
 	 	Maximum	 	 	 	Expiration	 	 	
 	 	Exposure	 	Nature of Guarantee	 	Date	 	Triggering Event	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
NRG Energy Second Priority Notes due 2013	 	$	1,753,000	 	 	Obligations under credit agreement	 	 	2013	 	 	Nonperformance	

20.	Sales to Significant Customers	
      For the period from December 6, 2003 to December 31, 2003, the Company derived approximately 40% of total revenues from one customer, Vattenfall Europe A.G. (“VEAG”). For the period from January 1, 2003 to December 5, 2003, sales to the same customer, VEAG, accounted for 34% of total revenues. During 2002 and 2001, the sales to VEAG accounted for 31% and 22%, respectively, of total revenues.

21.	Related Party Transactions	
      In December 2003, the Company sold 100% of its outstanding shares of Sterling Luxembourg (No. 4) S.a.r.L. (“Sterling”) which held an interest in Itiquira S.A., COBEE, Flinders Finance and several dormant

43

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

holding companies. Fifty percent of the total outstanding shares of Sterling were sold to NRG Latin America, Inc., a wholly owned subsidiary of NRG Energy and an affiliate of the Company, for $3 million, satisfied through a reduction of NRG Latin America, Inc.’s receivable from the Company. The remaining 50% of the total outstanding shares were sold to NRG Energy for $3 million, which consisted of a dividend distribution of one dollar, plus settlement of a payable to NRG Energy of $3 million. As part of this transfer of assets to affiliates, the Company entered into a note payable in the amount of $10.7 million with NRGenerating Holdings No. 21 BV, an indirect wholly owned subsidiary of NRG Energy and an affiliate of the Company. See Note 13 — Long Term Debt and Capital Leases.

      In accordance with SFAS No. 141 Business Combinations, because the transfer was between entities under common control, the provisions of APB Opinion No. 16,  Business Combinations,  applied. Therefore all activity related to the entities that were sold was removed from the financial statements of NRG International LLC as presented herein.

22.	Cash Flow Information	
      Detail of supplemental disclosures of cash flow and non-cash investing and financing information was:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized	 	 	
 	 	Company	 	Predecessor Company	

	 	

	
 	 	For the	 	For the	 	 	
 	 	Period from	 	Period from	 	 	
 	 	December 6,	 	January 1,	 	For the Years Ended	
 	 	2003 to	 	2003 to	 	December 31,	
 	 	December 31,	 	December 5,	 	

	
 	 	2003	 	2003	 	2002	 	2001	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands of dollars)	
Interest paid (net of amounts capitalized)	 	$	5,590	 	 	$	7,711	 	 	$	11,899	 	 	$	10,115	 	
Income taxes paid/(refunds)	 	 	13,499	 	 	 	(4,278	)	 	 	10,597	 	 	 	5,772	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
Detail of businesses and assets acquired:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Current assets (including restricted cash)	 	 	—	 	 	 	—	 	 	 	2	 	 	 	38,618	 	
 	Fair value of non-current assets	 	 	—	 	 	 	—	 	 	 	627	 	 	 	950,488	 	
 	Liabilities assumed, including deferred taxes	 	 	—	 	 	 	—	 	 	 	(218	)	 	 	(892,342	)	

	 	 	 	

	 	 	 	

	 	 	 	

	 	
 	Cash paid net of cash acquired	 	$	—	 	 	$	—	 	 	$	411	 	 	$	96,764	 	

	 	 	 	

	 	 	 	

	 	 	 	

	 	

 	2001 Significant Acquisitions included above:	
      In April 2001, the Company acquired additional interests in the MIBRAG and Schkopau projects in Germany, as well as 100% of the Csepel I and II power generation facilities in Hungary. The purchase price was approximately USD 190 million. Csepel consists of Csepel I, a 116 MW thermal plant, and Csepel II, a 389 MW gas turbine power station, both located in Csepel Island in Budapest. The Company completed the acquisition of the Hungarian assets in the second quarter of 2001. As disclosed in Note 4, the Company divested its interests in Csepel in 2002.

      In July 2001, the Company indirectly acquired approximately 60% of Hsin Yu Energy Development Company Ltd. (Hsin Yu), a Taiwan company that owns a 170 MW combined cycle gas turbine in an industrial park near Taipei. As disclosed in Note 4, the Company divested its interests in Hsin Yu in 2004.

      In September 2001, the Company acquired 100% interests in the 66 MW Cementos Pacasmayo and the 45 MW Cahua hydro facilities in Peru. As disclosed in Note 4, the Company divested its interests in the Peruvian companies in 2003.

44

 
NRG INTERNATIONAL LLC
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      In May 2001, the Company purchased 50% of Tosli Investments BV from Nordic Power Invest AB (Nordic Power), wholly owned subsidiary of Vattenfall AB.

      In July 2001, the Company indirectly acquired a 30% interest in the 355 MW Lanco Kondapalli Power Facility in Southeast India. As disclosed in Note 5, the Company divested its interests in Kondapalli in May 2003.

23.	Subsequent Events	
      The following events occurred subsequent to December 31, 2003.

 	Loy Yang	
      In April 2004, the Company completed the sale of its 25% interest in Loy Yang to Great Energy Alliance Corporation, which resulted in net proceeds of $26.7 million. No material gain or loss was recorded upon completion of the sale.

 	Hsin Yu	
      In May 2004, the Company sold its interest in Hsin Yu. Under the terms of the agreement, the Company received cash proceeds of approximately $1 million and was relieved of any future obligations related to the debt in the project.

45

 

REPORT OF INDEPENDENT AUDITORS
ON FINANCIAL STATEMENT SCHEDULE

To the Member of
NRG International LLC:

      Our audits of the consolidated financial statements referred to in our report dated October 29, 2004, also included an audit of the financial statement schedule listed herein. In our opinion, this financial statement schedule for the period from January 1, 2003 to December 5, 2003 and for the two years ended December 31, 2002, presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
 	 	
 	/s/ PRICEWATERHOUSECOOPERS LLP	

	
 	PricewaterhouseCoopers LLP	
Minneapolis, Minnesota
October 29, 2004

46

 

REPORT OF INDEPENDENT AUDITORS
ON FINANCIAL STATEMENT SCHEDULE

To the Member of
NRG International LLC:

      Our audits of the consolidated financial statements referred to in our report dated October 29, 2004, also included an audit of the financial statement schedule listed herein. In our opinion, this financial statement schedule for the period from December 6, 2003 to December 31, 2003 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
 	 	
 	/s/ PRICEWATERHOUSECOOPERS LLP	

	
 	PricewaterhouseCoopers LLP	
Minneapolis, Minnesota
October 29, 2004

47

 

NRG INTERNATIONAL LLC

SCHEDULE II. VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2003, 2002 and 2001

 	 	 	 	Additions	 	 	 	 	

	 	 	 	 	
 	 	Balance at	 	Charged to	 	 	 	 	 	Balance at	
 	 	Beginning of	 	Costs and	 	Charged to	 	 	 	End of	
Description	 	Period	 	Expenses	 	Other	 	Deductions	 	Period	

	 	

	 	

	 	

	 	

	 	

	
 	 	 	
 	 	(In thousands)	
Income tax valuation allowance, deducted from deferred tax assets in the balance sheet:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Predecessor Company	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Year ended December 31, 2001	 	$	50,057	 	 	$	21,389	 	 	$	—	 	 	$	—	 	 	$	71,446	 	
Year ended December 31, 2002	 	 	71,446	 	 	 	43,316	 	 	 	—	 	 	 	—	 	 	 	114,762	 	
January 1 - December 5, 2003	 	 	114,762	 	 	 	41,722	 	 	 	—	 	 	 	—	 	 	 	156,484	 	

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reorganized Company	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
December 6 - December 31, 2003	 	 	156,484	 	 	 	8	 	 	 	—	 	 	 	—	 	 	 	156,492	 	
48