8-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 8-K

CURRENT REPORT PURSUANT
TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934

Date of report (Date of earliest event reported) December 31, 2004

NRG Energy, Inc.

(Exact Name of Registrant as Specified in Its Charter)

Delaware

(State or Other Jurisdiction of Incorporation)

001-15891	41-1724239
(Commission File Number)	(IRS Employer Identification No.)
211 Carnegie Center	Princeton, NJ 08540
(Address of Principal Executive Offices)	(Zip Code)

609-524-4500

(Registrant’s Telephone Number, Including Area Code)

(Former Name or Former Address, if Changed Since Last Report)

     Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

     o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

     o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

     o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

     o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

1

TABLE OF CONTENTS

EX-99.1: NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES

EX-99.2: NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

EX-99.3: LOUISIANA GENERATING LLC

EX-99.4: NRG MID ATLANTIC GENERATING LLC AND SUBSIDIARIES

EX-99.5: INDIAN RIVER POWER LLC

EX-99.6: OSWEGO HARBOR POWER LLC

EX-99.7: NRG INTERNATIONAL LLC AND SUBSIDIARIES

Item 8.01 Other Items

NRG Energy, Inc., or NRG, is preparing to file a Pre-Effective Amendment No. 1 to the Registration Statement on Form S-4 to register its 8% second priority senior secured notes due 2013. In connection with this filing, NRG has filed herewith audited financial statements for seven significant subsidiaries of NRG pursuant to Rule 3-16 of Regulation S-X for the fiscal year ended December 31, 2004, which are incorporated herein by reference as Exhibits 99.1 to 99.7.

Item 9.01 Financial Statements and Exhibits

(a)	Financial Statements of Business Acquired (not applicable)
(b)	Pro Forma Financial Information (not applicable)
(c)	Exhibits

EXHIBIT 99.1	NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES
EXHIBIT 99.2	NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES
EXHIBIT 99.3	LOUISIANA GENERATING LLC
EXHIBIT 99.4	NRG MID ATLANTIC GENERATING LLC AND SUBSIDIARIES
EXHIBIT 99.5	INDIAN RIVER POWER LLC
EXHIBIT 99.6	OSWEGO HARBOR POWER LLC
EXHIBIT 99.7	NRG INTERNATIONAL LLC AND SUBSIDIARIES

2

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 hereunto duly authorized.

NRG Energy, Inc. (Registrant)
By:	/s/ TIMOTHY W. J. O’BRIEN
	Timothy W. J. O’Brien
	Vice President, General Counsel and Secretary

Dated: June 14, 2005

3

Exhibit Index

EXHIBIT 99.1	NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES
EXHIBIT 99.2	NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES
EXHIBIT 99.3	LOUISIANA GENERATING LLC
EXHIBIT 99.4	NRG MID ATLANTIC GENERATING LLC AND SUBSIDIARIES
EXHIBIT 99.5	INDIAN RIVER POWER LLC
EXHIBIT 99.6	OSWEGO HARBOR POWER LLC
EXHIBIT 99.7	NRG INTERNATIONAL LLC AND SUBSIDIARIES

4

EX-99.1

EXHIBIT 99.1

NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES

CONSOLIDATED FINANCIAL STATEMENTS

At December 31, 2004 and 2003,
and for the Year Ended December 31, 2004,
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

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NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES

INDEX

	Page
Reports of Independent Registered Public Accounting Firms		3
Consolidated Balance Sheets at December 31, 2004 and 2003		6
Consolidated Statements of Operations for the year ended December 31, 2004, 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		7
Consolidated Statements of Member’s Equity and Comprehensive Income for the year ended December 31, 2004, 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		8
Consolidated Statements of Cash Flows for the year ended December 31, 2004, 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		9
Notes to Consolidated Financial Statements		10

2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Member of
NRG Northeast Generating LLC

     We have audited the accompanying consolidated balance sheet of NRG Northeast Generating LLC and its subsidiaries as of December 31, 2004, and the related consolidated statements of operations, member’s equity and comprehensive income, and cash flows for the year then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

     We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

     In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of NRG Northeast Generating LLC and its subsidiaries as of December 31, 2004, and the results of their operations and their cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles.

/s/	KPMG LLP
	KPMG LLP

Philadelphia, Pennsylvania
May 27, 2005

3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Member of
NRG Northeast Generating LLC

     In our opinion, the accompanying consolidated statements of operations, of member’s equity and comprehensive income, and of cash flows present fairly, in all material respects, the results of operations and cash flows of NRG Northeast Generating LLC and its subsidiaries (“Predecessor Company”) for the period from January 1, 2003 to December 5, 2003 and for the year 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). 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 Notes 1 and 2 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

4

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Member of
NRG Northeast Generating LLC

     In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, of member’s equity and comprehensive income, and of cash flows present fairly, in all material respects, the financial position of NRG Northeast Generating LLC and its subsidiaries (“Reorganized Company”) at 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 audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 audit provides a reasonable basis for our opinion.

     As discussed in Notes 1 and 2 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

5

NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	Reorganized Company
	December 31,		December 31,
	2004		2003
	(In thousands of dollars)
ASSETS
Current assets
Cash and cash equivalents	$	24,888	$	6,250
Restricted cash		3,733		4,198
Accounts receivable, net of allowance for doubtful accounts of $0 and $0, respectively		3,139		306
Accounts receivable — affiliates		33,042		9,665
Inventory		155,499		107,441
Derivative instruments valuation		65,608		611
Prepayments and other current assets		34,789		33,812
Total current assets		320,698		162,283
Property, plant and equipment, net of accumulated depreciation of $49,374, and $2,911, respectively		835,089		843,832
Derivative instruments valuation		344		—
Intangible assets, net of accumulated amortization of $12,159, and $523, respectively		180,110		213,687
Deferred income taxes		—		91,565
Other assets		9,656		7,355
Total assets	$	1,345,897	$	1,318,722
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Note payable — affiliate	$	—	$	30,000
Accounts payable		12,212		177
Accrued interest		—		2,557
Accrued station service costs		33,490		25,645
Other accrued liabilities		5,571		25,580
Current deferred income taxes		260		453
Derivative instruments valuation		14,389		190
Total current liabilities		65,922		84,602
Deferred income taxes		24,570		—
Derivative instruments valuation		148		—
Other long-term obligations		14,162		7,528
Total liabilities		104,802		92,130
Commitments and contingencies
Member’s equity		1,241,095		1,226,592
Total liabilities and member’s equity	$	1,345,897	$	1,318,722

The accompanying notes are an integral part of these consolidated financial statements.

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NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Reorganized Company						Predecessor Company
				For the			For the
				Period from			Period from
	For the Year			December 6,			January 1,			For the Year
	Ended			2003 to			2003 to			Ended
	December 31,			December 31,			December 5,			December 31,
	2004			2003			2003			2002
	(In thousands of dollars)
Revenues	$	1,032,075		$	60,471		$	730,463		$	693,869
Operating costs		629,666			40,710			599,266			494,446
Depreciation		46,513			2,911			61,271			54,227
General and administrative expenses		69,244			4,205			40,927			44,262
Reorganization items		179			241			5,149			—
Restructuring and impairment charges		247			—			230,570			50,524
Income (loss) from operations		286,226			12,404			(206,720	)		50,410
Other income, net		4,457			5			1,955			5,273
Interest expense		(791	)		(2,103	)		(50,746	)		(51,798	)
Income (loss) before income taxes		289,892			10,306			(255,511	)		3,885
Income tax expense (benefit)		124,764			4,460			(109,824	)		3,460
Net income (loss)	$	165,128		$	5,846		$	(145,687	)	$	425

The accompanying notes are an integral part of these consolidated financial statements.

7

NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY AND COMPREHENSIVE INCOME

											Accumulated
					Member’s			Accumulated			Other			Total
	Member’s				Contributions/			Net Income			Comprehensive			Member’s
	Units		Amount		Distributions			(Loss)			Income/(loss)			Equity
	(In thousands of dollars)
Balances at December 31, 2001 (Predecessor Company)		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 member		—		—		16,931			—			—			16,931
Balances at December 31, 2002 (Predecessor Company)		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 member		—		—		15,945			—			—			15,945
Distribution to member		—		—		(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 member		—		—		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
Impact of SFAS No. 133 for the year ending December 31, 2004, net of income tax of $1,102		—		—		—			—			1,462			1,462
Net income		—		—		—			165,128			—			165,128
Comprehensive income		—		—		—			—			—			166,590
Distribution to member		—		—		(152,087	)		—			—			(152,087	)
Balances at December 31, 2004 (Reorganized Company)		1,000	$	1	$	1,068,658		$	170,974		$	1,462		$	1,241,095

The accompanying notes are an integral part of these consolidated financial statements.

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NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Reorganized Company						Predecessor Company
				For the			For the
				Period from			Period from
	For the Year			December 6,			January 1,			For the Year
	Ended			2003 to			2003 to			Ended
	December 31,			December 31,			December 5,			December 31,
	2004			2003			2003			2002
				(In thousands of dollars)
Cash flows from operating activities
Net income (loss)	$	165,128		$	5,846		$	(145,687	)	$	425
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation		46,513			2,911			61,271			54,227
Amortization of debt issuance costs		—			—			8,995			411
Amortization of intangible assets		11,636			523			2,172			—
Deferred income taxes		114,840			320			(125,769	)		(13,471	)
Current tax expense — noncash contribution from member		9,924			4,140			15,945			16,931
Asset impairment		247			—			230,570			49,289
Unrealized gains on derivatives		(48,430	)		(516	)		(16,676	)		(14,457	)
Allowance for doubtful accounts		—			—			—			50,712
Loss on disposal of assets		359			350			1,514			—
Changes in assets and liabilities
Accounts receivable		(2,833	)		—			117,847			(112,840	)
Accounts receivable/payable — affiliates		(11,131	)		14,684			(35,825	)		11,476
Inventory		(48,058	)		1,233			(7,977	)		48,252
Prepayments and other current assets		(977	)		(4,386	)		8,883			(18,193	)
Accounts payable		12,035			103			(14,543	)		12,057
Accrued interest		(2,557	)		(23,785	)		22,144			2,038
Accrued station service costs and other accrued liabilities		(2,469	)		(8,109	)		10,463			(19,396	)
Changes in other assets and liabilities		3,718			35			(32,340	)		4,149
Net cash provided by (used in) operating activities		247,945			(6,651	)		100,987			71,610
Cash flows from investing activities
Decrease (increase) in restricted cash		465			(590	)		(3,608	)		—
Capital expenditures		(37,761	)		(1,221	)		(14,692	)		(34,126	)
Net cash used in investing activities		(37,296	)		(1,811	)		(18,300	)		(34,126	)
Cash flows from financing activities
Proceeds from debt issuance — affiliate		—			—			—			30,000
Principal payments on note payable-affiliate		(30,000	)		—			—			—
Contribution from member		—			565,954			—			—
Distribution to member		(162,011	)		—			(91,783	)		—
Principal payments on long-term debt		—			(556,500	)		—			(53,500	)
Net cash (used in) provided by financing activities		(192,011	)		9,454			(91,783	)		(23,500	)
Net change in cash and cash equivalents		18,638			992			(9,096	)		13,984
Cash and cash equivalents
Beginning of period		6,250			5,258			14,354			370
End of period	$	24,888		$	6,250		$	5,258		$	14,354
Supplemental disclosures of cash flow information
Cash paid for interest	$	3,540		$	25,888		$	24,786		$	49,760

The accompanying notes are an integral part of these consolidated financial statements.

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NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization

     NRG Northeast Generating LLC, or the Company, or NRG Northeast, a wholly owned subsidiary of NRG Energy, Inc., or NRG Energy, owns electric power generation plants in the northeastern region of the United States. 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.

     From May 14 to December 23, 2003, NRG Energy and a number of its subsidiaries, including NRG Northeast, undertook a comprehensive reorganization and restructuring under chapter 11 of the United States Bankruptcy Code. The Northeast/South Central Plan of Reorganization, relating to the Company, the NRG South Central LLC subsidiaries and the other NRG Northeast subsidiaries, 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.

     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 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 and Basis of Presentation

     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 Statement of Position 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code”, or SOP 90-7.

     For financial reporting purposes, close of business on December 5, 2003, represents the date of the Company’s emergence from bankruptcy because that is the date of emergence for the ultimate parent company, NRG Energy. As previously stated, the Company emerged from bankruptcy on December 23, 2003. The accompanying financial statements reflect the impact of the Company’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, pre-emergence from bankruptcy
	The Company’s operations prior to December 6, 2003
“Reorganized Company”	The Company, post-emergence from bankruptcy
	The Company’s operations, December 6, 2003 - December 31, 2004

     The consolidated financial statements include our accounts and operations and those of our subsidiaries in which we have a controlling interest. All significant intercompany transactions and balances have been eliminated in consolidation.

   Fresh Start Reporting/Push Down Accounting

     In accordance with SOP 90-7, 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 immediately before confirmation receive less than 50 percent of the voting shares of the emerging entity. NRG Energy met these requirements and adopted Fresh Start reporting resulting in the creation of a new reporting entity designated as Reorganized NRG. 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.

     The bankruptcy court issued a confirmation order approving 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. The Xcel Energy settlement agreement was entered into on December 5,

10

NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES

2003. NRG Energy 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.

     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, or SFAS No. 109, “Accounting for Income Taxes”. The net effect of all Fresh Start adjustments resulted in a gain of $3.9 billion (comprised of a $4.1 billion gain from continuing operations and a $0.2 billion loss from discontinued operations), 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 and push down accounting 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 NRG Energy’s 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 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. 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.

     A separate plan of reorganization was filed for NRG Northeast 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, NRG Energy accounted for these entities as if they had emerged from bankruptcy at the same time that NRG Energy emerged, as it is believed that NRG Energy continued to maintain control over the NRG Northeast facilities throughout the bankruptcy process.

     Due to the adoption of Fresh Start upon NRG Energy’s emergence from bankruptcy and the impact of push down accounting, the Reorganized Company’s 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.

   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 to satisfy the requirements of certain debt agreements and funds held within the Company’s projects that are restricted in their use. These funds are used to pay for current operating expenses and current debt service payments, per the restrictions of the debt agreements.

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NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES

   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. On December 5, 2003, the Company 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 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.

Facilities and equipment	9 to 26 years
Office furnishings and equipment	2 to 6 years

   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.

   Intangible Assets

     Intangible assets represent contractual rights held by the Company. Intangible assets are amortized over their economic useful life and reviewed for impairment whenever events or changes in circumstances indicate carrying values may not be recoverable.

     Intangible assets consist primarily of the fair value of power sales agreements and emission allowances. The amounts related to the power sales agreements are amortized as a reduction to revenue over the terms and conditions of each contract. Emission allowance related amounts are 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. Electric energy revenue is recognized upon transmission to the customer. 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, or ISO, and in which the Company has entered into a netting agreement with the 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 agreements with a marketing affiliate for the sale of energy, capacity and ancillary services produced, 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. See Note 12 — Related Party Transactions.

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NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES

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 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 income taxes payable resulting from the tax provision are reflected as a contribution by member in the consolidated statement of member’s 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 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.

   Credit Risk

     Credit risk relates to the risk of loss resulting from non-performance or non-payment by counter-parties pursuant to the terms of their contractual obligations. NRG Energy monitors and manages the credit risk of its affiliates, including the Company and its subsidiaries, through credit policies which include an (i) established credit approval process, (ii) daily monitoring of counter-party credit limits, (iii) the use of credit mitigation measures such as margin, collateral, credit derivatives or prepayment arrangements, (iv) the use of payment netting agreements and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counter-party. Risk surrounding counter-party performance and credit could ultimately impact the amount and timing of expected cash flows. NRG Energy has credit protection within various agreements to call on additional collateral support if necessary.

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

   Fair Value of Financial Instruments

     The carrying amount of cash and cash equivalents, restricted cash, receivables, accounts payables, and accrued liabilities approximate fair value because of the short maturity of these instruments. The fair value of note payable — affiliate approximates carrying value as the underlying instrument bears a variable market interest rate.

   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, disclosure of contingent 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 member’s equity as previously reported.

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NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES

   Recent Accounting Pronouncements

     In November 2004, the FASB issued SFAS No. 151, “Inventory Costs- an amendment of ARB No. 43, Chapter 4”. This statement amends the guidance in ARB No. 43, Chapter 4, “Inventory Pricing”, and requires that idle facility expense, excessive spoilage, double freight, and rehandling costs be recognized as current-period charges regardless of whether they meet the criterion of “so abnormal” established by Accounting Research Bulletin No. 43. SFAS No. 151 is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The Company is currently in the process of evaluating the potential impact that the adoption of this statement will have on the Company’s consolidated financial position and results of operations.

     In December 2004, the FASB issued two FASB Staff Positions, or FSPs, regarding the accounting implications of the American Jobs Creation Act of 2004 related to (1) the deduction for qualified domestic production activities (FSP FAS 109-1) and (2) the one-time tax benefit for the repatriation of foreign earnings (FSP FAS 109-2). In FSP FAS 109-1, “Application of FASB Statement No. 109, “Accounting for Income Taxes,” to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004”, the Board decided that the deduction for qualified domestic production activities should be accounted for as a special deduction under FASB Statement No. 109, “Accounting for Income Taxes” and rejected an alternative view to treat it as a rate reduction. Accordingly, any benefit from the deduction should be reported in the period in which the deduction is claimed on the tax return. FSP FAS 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004”, addresses the appropriate point at which a company should reflect in its financial statements the effects of the one-time tax benefit on the repatriation of foreign earnings. Because of the proximity of the Act’s enactment date to many companies’ year-ends, its temporary nature, and the fact that numerous provisions of the Act are sufficiently complex and ambiguous, the Board decided that absent additional clarifying regulations, companies may not be in a position to assess the impact of the Act on their plans for repatriation or reinvestment of foreign earnings. Therefore, the Board provided companies with a practical exception to FAS 109’s requirements by providing them additional time to determine the amount of earnings, if any, that they intend to repatriate under the Act’s beneficial provisions. The Board confirmed, however, that upon deciding that some amount of earnings will be repatriated, a company must record in that period the associated tax liability, thereby making it clear that a company cannot avoid recognizing a tax liability when it has decided that some portion of its foreign earnings will be repatriated. The Company is currently in the process of evaluating the potential impact that the adoption of FSP FAS 109-1 will have on our consolidated financial position and results of operations. The Company does not believe that the potential adoption of FSP 109-2 will have a material impact on our consolidated financial position and results of operation.

     In March 2005, the Financial Accounting Standards Board (FASB) issued Interpretation No. 47 (FIN 47) to Financial Accounting Standard No. 143 (SFAS No. 143) governing the application of Asset Retirement Obligations. FIN 47 clarifies that the term “conditional asset retirement obligation” as used in SFAS 143. SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional but there may remain some uncertainty as to the timing and/or method of settlement. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred — generally upon acquisition, construction, or development and/or through the normal operation of the asset. SFAS No. 143 acknowledges that in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation. FIN 47 clarifies when the company would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective for fiscal years ending after December 15, 2005 and we are currently evaluating the impact of this guidance.

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NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES

3. Emergence from Bankruptcy and Fresh Start Reporting

     In accordance with the requirement of SFAS No. 141, “Business Combinations” and push down accounting, the Company’s fair value of $650.7 million, as of the Fresh Start date, 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 Fresh Start 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 Fresh Start.

     The effects of the push down accounting adjustments on the Company’s condensed 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)
Current Assets	$	233,044	$	(61,423	)	$	171,621
Non-current Assets		1,114,856		44,455			1,159,311
Total Assets	$	1,347,900	$	(16,968	)	$	1,330,932
Current Liabilities		672,345		442			672,787
Non-current Liabilities		4,749		2,744			7,493
		677,094		3,186			680,280
Members’ Equity		670,806		(20,154	)		650,652
Total Liabilities and Member’s Equity	$	1,347,900	$	(16,968	)	$	1,330,932

4. Other Charges

     Restructuring and impairment charges and reorganization items included in the consolidated statement of operations include the following:

	Reorganized Company
			For the
			Period from		Predecessor Company
	For the		December 6,		For the Period From		For the
	Year Ended		2003 through		January 1, 2003		Year Ended
	December 31,		December 31,		through December 5,		December 31,
	2004		2003		2003		2002
	(In thousands of dollars)
Restructuring and impairment charges	$	247	$	—	$	230,570	$	50,524
Reorganization items		179		241		5,149		—
	$	426	$	241	$	235,719	$	50,524

   Restructuring and Impairment Charges

     The Company reviews 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 $0.2 million for the year ended December 31, 2004, $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. 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.

     Restructuring and impairment charges included the following asset impairments for the year ended December 31, 2004, the period from January 1, 2003 to December 5, 2003 and for the year ended December 31, 2002:

			Predecessor Company
			For the
	Reorganized Company		Period from
	For the		January 1,		For the
	Year Ended		2003 through		Year Ended
	December 31,		December 5,		December 31,
	2004		2003		2002		Fair Value Basis
	(In thousands of dollars)
Devon Power LLC	$	247	$	64,198	$	—	Projected cash flows
Middletown Power LLC		—		157,323		—	Projected cash flows
Arthur Kill Power LLC		—		9,049		—	Projected cash flows
Somerset Power LLC		—		—		49,289	Projected cash flows
Total impairment charges		247		230,570		49,289
Consulting fees related to pending bankruptcy		—		—		1,235
Total restructuring and impairment charges	$	247	$	230,570	$	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, or FERC’s, orders on Peaking Units Safe Harbor, or PUSH, pricing, the pending termination of the Reliability Must Run Agreements, or RMRs, 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 $64.2 million and $157.3 million as impairment charges at Devon Power LLC and Middletown Power LLC, respectively. In the third quarter of 2003, ISO-NE informed the Company that it

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NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES

would not extend the RMR contract for Devon Units 7 and 8. As a result, both units were placed on deactivated reserve and the Company recorded an additional impairment of $0.2 million for Devon Power LLC.

     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 $9.0 million to write-off assets under construction.

     Somerset Power LLC — 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 unrecognized gain on the interest rate lock entered into by the Company upon the issuance of the Company’s debt.

	Reorganized Company
			For the		Predecessor
			Period from		Company
	For the		January 1,		For the
	Year Ended		2003 through		Year Ended
	December 31,		December 5,		December 31,
	2004		2003		2002
	(In thousands of dollars)
Reorganization items
Consulting and legal fees	$	179	$	241	$	(1,270	)
Deferred financing costs		—		—		(3,350	)
Pre-payment charge		—		—		(8,348	)
Write-off of interest rate lock		—		—		18,117
Total reorganization items	$	179	$	241	$	5,149

5. Inventory

     Inventory, which is valued at the lower of weighted average cost or market, consists of:

	Reorganized Company
	December 31,		December 31,
	2004		2003
	(In thousands of dollars)
Fuel oil	$	108,904	$	66,915
Spare parts		24,836		24,947
Coal		21,473		12,163
Kerosene		286		3,416
Total inventory	$	155,499	$	107,441

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NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES

6. Property, Plant and Equipment

     The major classes of property, plant and equipment were as follows:

								Average
		Reorganized Company						Remaining
	Depreciable	December 31,			December 31,			Useful
	Lives	2004			2003			Life
		(In thousands of dollars)
Facilities, machinery and equipment	9-26 years	$	826,439		$	802,173		15 years
Land and improvements			34,266			34,266
Construction in progress			21,410			9,689
Office furnishings and equipment	2-6 years		2,348			615		2 years
Total property, plant and equipment			884,463			846,743
Accumulated depreciation			(49,374	)		(2,911	)
Property, plant and equipment, net		$	835,089		$	843,832

7. Asset Retirement Obligations

     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 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, the period from December 6, 2003 to December 31, 2003 and the year ended December 31, 2004. Revisions to estimates were recorded as changes to planned asset retirement obligations were made. The asset retirement obligation is included in other long-term obligations in the consolidated balance sheet. As a result of adopting Fresh Start, the Company revalued its asset retirement obligations on December 6, 2003. The Company recorded an increase to its retirement obligation of $2.7 million in connection with push down accounting. This amount results from a change in the discount rate used between adoption and Fresh Start reporting as of December 5, 2003, equal to 500 to 600 basis points.

	Reorganized Company
			Accretion for						Accretion for
	Beginning		Period		Ending				the Year		Ending
	Balance		December 6 to		Balance		Revisions		ended		Balance
	December 6,		December 31,		December 31,		to		December 31,		December 31,
	2003		2003		2003		Estimate		2004		2004
	(In thousands of dollars)
Dunkirk Power LLC	$	2,665	$	12	$	2,677	$	—	$	183	$	2,860
Huntley Power LLC		4,326		20		4,346		—		297		4,643
Somerset Power LLC		502		3		505		—		35		540
Arthur Kill Power LLC		—		—		—		159		—		159
Astoria Gas Turbine Power LLC		—		—		—		169		—		169
Oswego Harbor Power LLC		—		—		—		287		—		287
	$	7,493	$	35	$	7,528	$	615	$	515	$	8,658

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NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES

	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
Somerset Power LLC		313		—		40		149		502
	$	313	$	4,035	$	401	$	2,744	$	7,493

8. Intangible Assets

   Reorganized Company

     Upon the adoption of Fresh Start and application of push down accounting, the Company established certain intangible assets for power sales agreements and plant emission allowances. These intangible assets are amortized over their respective lives based on a straight-line or units of production basis.

     Power sale agreements are amortized as a reduction to revenue over the terms and conditions of each contract. The power sale agreements were fully amortized in May 2004. Emission allowances are amortized as additional fuel expense based upon the actual level of emissions from the respective plants through 2023. Aggregate amortization recognized for the year ended December 31, 2004 and period from December 6, 2003 through December 31, 2003 was approximately $11.6 million and $0.5 million, respectively. The annual aggregate amortization for each of the five succeeding years is expected to approximate $5.0 million in 2005, $4.3 million in 2006, $3.6 million in 2007, $3.1 million in 2008 and $2.8 million in 2009.

     Intangible assets were reduced by $21.9 million during the year ended December 31, 2004 consisting of a $10.4 million reduction in connection with the recognition of certain tax credits to be claimed on the Company’s New York State franchise tax return and $11.5 million of adjustments related to a true-up of certain tax evaluations.

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NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES

     Intangible assets consisted of the following:

	Power Sale			Emission
	Agreements			Allowances			Total
	(In thousands of dollars)
Original balances as of December 6, 2003	$	3,140		$	211,070		$	214,210
Amortization		(523	)		—			(523	)
Balances as of December 31, 2003		2,617			211,070			213,687
Amortization		(2,617	)		(9,019	)		(11,636	)
Other adjustments		—			(21,941	)		(21,941	)
Balances as of December 31, 2004	$	—		$	180,110		$	180,110

   Predecessor Company

     The Company had intangible assets that were amortized and consisted of service contracts that were terminated at bankruptcy. Amortization expense recognized for the period January 1, 2003 to December 5, 2003 and for the year ended December 31, 2002, was approximately $2.2 million and $0.9 million, respectively.

9. Note Payable — Affiliate

     On June 15, 2002, NRG Energy loaned the Company $30 million to fund capital expenditures. The note payable bore interest at the three-month London Interbank Offered Rate plus 0.5%. The note payable was subordinate to the debt of NRG Energy and was subject to the terms and conditions of the senior secured bonds’ indenture. The note payable was paid along with accrued interest of $1.0 million in March 2004. Accordingly, the Company has classified this loan as a short-term affiliated note payable at December 31, 2003.

10. Accounting for Derivative Instruments and Hedging Activity

     SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” as amended by SFAS No. 137, SFAS No. 138 and SFAS No. 149 requires the Company to recognize all derivative instruments on the balance sheet as either assets or liabilities and measure them at fair value each reporting period. If certain conditions are met, the Company may be able to designate derivatives as cash flow hedges and defer the effective portion of the change in fair value of the derivatives in Accumulated Other Comprehensive Income (OCI) and subsequently recognize in earnings when the hedged items impact income. The ineffective portion of a cash flow hedge is immediately recognized in income.

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

     For derivatives that are neither designated as cash flow hedges or do not qualify for hedge accounting treatment, the changes in the fair value will be immediately recognized in earnings.

     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, 2004, the Company had various commodity contracts extending through December 2005 .

   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, NRG Power Marketing 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.

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NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES

     During the year ended December 31, 2004, 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, the Company recognized no gain or loss due to ineffectiveness of commodity cash flow hedges.

     The Company’s earnings for the year ended December 31, 2004, 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, were increased by unrealized gains of $48.4 million, $0.5 million, $16.7 million, and $14.5 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.

     Accumulated Other Comprehensive Income

     The following table summarizes the effects of SFAS No. 133, as amended, on the Company’s other comprehensive income balance attributable to hedged derivatives for the year ended December 31, 2004, 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:

	Reorganized Company					Predecessor Company
				For the		For the
				Period from		Period from
	For the Year			December 6,		January 1,			For the Year
	Ended			2003 to		2003 to			Ended
	December 31,			December 31,		December 5,			December 31,
	2004			2003		2003			2002
	(In thousands of dollars)
Energy Commodities Gains (Losses)
Beginning accumulated OCI balance	$	—		$	—	$	28,835		$	107,741
Unwound from OCI during period due to unwinding of previously deferred amounts		6,643			—		(28,835	)		(48,086	)
Mark to market of hedge contracts		(4,079	)		—		—			(30,820	)
Current year tax effect		(1,102	)		—		—			—
Ending accumulated OCI balance	$	1,462		$	—	$	—		$	28,835
Gains expected to unwind from OCI during next 12 months	$	1,462

     During the year ended December 31, 2004, the Company reclassified losses of $6.6 million from OCI to current period earnings. 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 years ended December 31, 2004 and 2002, the Company recorded losses in OCI of approximately $4.1 million and $30.8 million related to changes in the fair values of derivatives accounted for as hedges.

   Statement of Operations

     The following table summarizes the pre-tax effects of non-hedge derivatives and derivatives that no longer qualify as hedges on the Company’s statement of operations for the year ended December 31, 2004, 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:

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NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES

	Reorganized Company					Predecessor Company
				For the		For the
				Period from		Period from
	For the Year			December 6,		January 1,			For the Year
	Ended			2003 to		2003 to			Ended
	December 31,			December 31,		December 5,			December 31,
	2004			2003		2003			2002
	(In thousands of dollars)
Energy Commodities Gains
Revenues	$	48,625		$	3	$	18,241		$	(10,706	)
Operating costs		(195	)		513		(1,565	)		25,163
Total statement of operations impact before tax	$	48,430		$	516	$	16,676		$	14,457

11. Financial Instruments

     The estimated fair values of the Company’s recorded financial instruments are as follows:

	Reorganized Company
	December 31, 2004				December 31, 2003
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
	(In thousands of dollars)
Cash and cash equivalents	$	24,888	$	24,888	$	6,250	$	6,250
Restricted cash		3,733		3,733		4,198		4,198
Accounts receivable		3,139		3,139		306		306
Accounts receivable — affiliates		33,042		33,042		9,665		9,665
Note payable — affiliate		—		—		30,000		30,000
Accounts payable		12,212		12,212		177		177

     For cash and cash equivalents, restricted cash, accounts receivable and accounts payable, the carrying amount approximates fair value because of the short-term maturity of those instruments. The fair value of note payable — affiliate approximates carrying value as the underlying instruments bear a variable market interest rate.

12. Related Party Transactions

     Certain of the subsidiaries of the Company have entered into energy marketing services agreements with NRG Power Marketing Inc., or NRG Power Marketing, a wholly owned subsidiary of NRG Energy. The agreements are effective for consecutive one-year terms until terminated by either party upon 90 days written notice before the end of any such term. 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 affect 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 costs, taxes, labor, contract services, etc.). The Company incurs no fees related to these agreements with NRG Power Marketing.

     The Company has no employees and has entered into operation and maintenance agreements with NRG Operating Services, Inc., or 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, NRG Operating Services operates and maintains the respective facilities, 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.

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NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES

     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. These costs are reflected in operating costs in the consolidated statements of operations

     Effective January 1, 2005, the generating facilities at Huntley, Dunkirk and Oswego terminated their operating and maintenance agreements with NRG Operating Services, Inc., and assumed responsibility for all service formerly provided under the agreements.

     For the year ended December 31, 2004, 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, the Company incurred operating costs billed from NRG Operating Services totaling $286.9 million, $13.1 million, $169.7 million and $147.5 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 year ended December 31, 2004, 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, the Company paid NRG Energy approximately $39.8 million, $2.5 million, $9.7 million and $4.2 million, respectively, for corporate support and services. The amounts paid for the year ended December 31, 2004 reflect an overall increase in corporate level general and administrative expenses. Corporate general, administrative and development expenses increase in 2004 due to higher legal fees, increased audit costs and increased consulting costs due to NRG Energy’s Sarbanes-Oxley implementation. The method of allocating these costs remained the same from the prior years.

     At December 31, 2004 and December 31, 2003, the Company had an accounts receivable – affiliates balance of $33.0 million and $9.7 million, respectively. These balances are settled on a periodic basis and are due from multiple entities which are wholly owned subsidiaries of NRG Energy Inc, the parent company of Northeast Generating LLC.

13. Sales to Significant Customers

     For the year ended December 31, 2004, NRG Northeast derived approximately 86.0% of total revenues from two customers: NYISO accounted for 65.2% and ISO-New England accounted for 20.8%. For the period from December 6, 2003 to December 31, 2003, NRG Northeast derived approximately 89.4% of total revenues from two customers: NYISO accounted for 60.7% and ISO-New England accounted for 28.7%. For the period from January 1, 2003 to December 5, 2003, NRG Northeast derived approximately 99.3% of total revenues from two customers: NYISO accounted for 80.0% and Connecticut Light and Power accounted for 19.3%. During 2002, sales to one customer, NYISO, accounted for 72.5% of NRG Northeast’s gross revenue. NYISO and ISO-New England are FERC-regulated independent system operators or regional transmission organizations that manage transmission assets collectively under their control to provide non-discriminatory access to their respective transmission grids. We anticipate that NYISO and ISO-New England will continue to be significant customers given the scale of our asset base in these areas.

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 2008. Rental expense under these operating leases was approximately $0.2 million, $0 million, $0.9 million, and $0.8 million for the year ending December 31, 2004, the period from December 6, 2003 to December 31, 2003, for the period from January 1, 2003 to December 5, 2003, and for the year ending December 31, 2002, respectively. Future minimum lease payments under these leases for the years ending after December 31, 2004, are as follows:

	Total
	(In thousands
	of dollars)
2005	$	245
2006		198
2007		21
2008		7

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NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES

   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 U. S. These laws and regulations generally require lengthy and complex processes to obtain permits and licenses from federal, state and local agencies. If such laws and regulations become more stringent or new laws, interpretations or compliance policies, apply, 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 pollutants released at its facilities or at off-site locations where it may have sent waste, even if the release or off-site disposal was conducted in compliance with the law. In general, the effect of future laws or regulations is expected to require the addition of pollution control equipment or the composition of restrictions on the Company’s operations.

     Under various federal, state and local environmental laws and regulations, a current or previous owner or operator of any facility, 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 impose strict (without fault) and joint and several liability. The cost of investigation, remediation or removal of any hazardous or toxic substances or petroleum products could be substantial. 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.

     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.

     In response to liabilities associated with these activities, NRG Northeast establishes accruals where it is probable that it will incur environmental costs under applicable law or contracts and it is possible to reasonably estimate these costs. NRG Northeast adjusts the accruals when new remediation or other environmental liability responsibilities are discovered and probable costs become estimable, or when current liability estimates are adjusted to reflect new information or a change in the law. At December 31, 2004 and 2003, NRG Northeast has established such accruals in the amount of approximately $4.0 million, primarily related to its Arthur Kill and Astoria projects. In 2004 NRG Northeast also established accruals of $1.5 million related to its Connecticut projects.

     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 Dunkirk and Huntley, ash is disposed of 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. NRG Northeast has funded a trust to provide such financial assurance in the amount of $5.9 million which approximate fair value.

     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 and has funded a trust in the amount of $1.5 million accordingly.

     The Company inherited historical clean-up liabilities when it acquired the Somerset, Devon, Middletown, Montville, Norwalk Harbor, Arthur Kill and Astoria Generating Stations. During installation of a sound wall at Somerset Station in 2003, oil contaminated soil was encountered. The Company has delineated the general extent of contamination, determined it to be minimal, and has placed an activity use limitation on that section of the property. Site contamination liabilities arising under the Connecticut Transfer Act at Devon, Middletown, Montville and Norwalk Harbor Stations have been identified. The Company has proposed a remedial action plan to be implemented over the next two to eight years (depending on the station) to address historical ash contamination at the facilities. The total estimated cost is not expected to exceed $1.5 million. Remedial obligations at the Arthur Kill generating station have been established in discussions between the Company and the NYSDEC and are estimated to cost between $1 million and $2 million. Remedial investigations continue at the Astoria generating station with long-term clean-up liability expected to be within the range of $2.5 million to $4.3 million. While installing groundwater monitoring wells at Astoria to track our remediation of a historical fuel oil spill, the drilling contractor encountered deposits of coal tar in two borings. The Company reported the coal tar discovery to the

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NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES

NYSDEC in 2003 and delineated the extent of this contamination. The Company may also be required to remediate the coal tar contamination and/or record a deed restriction on the property if significant contamination is to remain in place.

     Huntley Power LLC, Dunkirk Power LLC and Oswego Power LLC were issued Notices of Violation for opacity exceedances and entered into a Consent Order with NYSDEC, effective March 31, 2004. The Consent Order required the respondents to pay a collective civil penalty of $1 million which was paid in April 2004. The Order also establishes stipulated penalties (payable quarterly) for future violations of opacity requirements and a compliance schedule. The Company is currently in dispute with NYSDEC over the method of calculation for any such stipulated penalties. The Company has placed $0.9 million in a reserve as of December 31, 2004, and does not believe that the final resolution will involve a material larger amount.

   NYISO Claims

     In November 2002, 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. New York City mitigation adjustments totaled $11.4 million. The issue related to NYISO’s concern that NRG would not have sufficient revenue to cover subsequent revisions to its energy market settlements. As of December 31, 2004, NYISO held $3.9 million in escrow for such future settlement revisions.

   Guarantees

     In November 2002, FASB issued FASB Interpretation, or FIN, No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”. In connection with the adoption of Fresh Start, all outstanding guarantees were considered new; accordingly, the Company applied the provisions of FIN 45 to all of the guarantees.

     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, 2004, the Company’s obligations pursuant to its guarantees of the performance obligations of its affiliates and subsidiaries totaled approximately $12.3 million. No amount has been recorded as a liability as of December 31, 2004.

     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.

     NRG Energy’s payment obligations under the notes and all related Parity Lien Obligations are guaranteed on an unconditional basis by certain of NRG Energy’s current and future restricted subsidiaries (other than certain excluded project subsidiaries, foreign subsidiaries and certain other 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.

     On December 24, 2004, NRG Energy’s credit facility was amended and restated, or the Amended Credit Facility, whereby NRG Energy repaid outstanding amounts and issued a $450.0 million, seven-year senior secured term loan facility, a $350.0 million funded letter of credit facility, and a three-year revolving credit facility in an amount up to $150.0 million. The Amended 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 NRG Energy including the following direct and indirect wholly owned subsidiaries:

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NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES

Subsidiary

NRG Northeast Generating LLC (Direct)
Arthur Kill Power LLC (Indirect)
Astoria Gas Turbine Power LLC (Indirect)
Connecticut Jet Power LLC (Indirect)
Devon Power LLC (Indirect)
Dunkirk Power LLC (Indirect)
Huntley Power LLC (Indirect)
Middletown Power LLC (Indirect)
Montville Power LLC (Indirect)
Norwalk Power LLC (Indirect)
Oswego Harbor Power LLC (Indirect)
Somerset Power LLC (Indirect)

     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	$	1,725,000	Obligations under credit agreement		2013	Nonperformance
NRG Energy Amended and Restated Credit Agreement	$	800,000	Obligations under credit agreement		2011	Nonperformance
Devon/Middletown/ Montville/Norwalk	$	2,339	Performance	None stated		Nonperformance
NRG Power Marketing, as agent for NRG Northeast	$	10,000	Performance	None stated		Nonperformance

     On February 4, 2005, NRG Energy redeemed and retired $375.0 million of Second Priority Notes. As a result of the retirement, the joint and several payment and performance guarantee obligation of the Company and the above listed subsidiaries was reduced from $1,725.0 million to $1,350.0 million.

   Legal Issues

   Consolidated Edison Co. of New York v. Federal Energy Regulatory Commission, Docket No. 01-1503

     Consolidated Edison and others petitioned the U.S. Court of Appeals for the District of Columbia Circuit for review of certain FERC orders in which FERC refused to order a re-determination of prices in the NYISO operating reserves markets for the period from January 29, 2000 to March 27, 2000. 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 from the non-spinning market of a generating facility known as Blenheim-Gilboa and resources located in western New York also constituted a tariff violation and/or whether these exclusions enabled NYISO to use its Temporary Extraordinary Procedure or TEP authority to require refunds. On March 4, 2005, FERC issued an order stating that no refunds would be required for the tariff violation associated with the pricing of spinning reserves. In the order, FERC also stated that the exclusion of the Blenheim-Gilboa facility and western reserves from the non-spinning market was not a market flaw and the NYISO was correct not to use its TEP authority to revise the prices in this market. A motion for rehearing of the Order was filed by the April 3, 2005 deadline. If the March 4, 2005 order is reversed and 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 would share responsibility for payment of any such refunds, under the petitioners’ theory the cumulative exposure to our above-listed entities could 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, or ECRC, appealed to the U.S. Court of Appeals for the District of Columbia Circuit a 2003 FERC decision 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. On May 13, 2005, the court denied ECRC’s appeal upholding the 2003 FERC decision. A petition for rehearing may be filed within 45 days of the decision.

   Connecticut Light & Power Company v. NRG Power Marketing Inc., Docket No. 3:01-CV-2373 (AWT), U.S District Court, District of Connecticut (filed on November 28, 2001)

     Connecticut Light & Power Company, or CL&P, sought recovery of amounts it claimed it was owed for congestion charges under the terms of an October 29, 1999 contract between the parties. CL&P withheld approximately $30 million from amounts owed to

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NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES

NRG Power Marketing, Inc., or PMI, and PMI counterclaimed. CL&P filed its motion for summary judgment to which PMI filed a response on March 21, 2003. By reason of the stay issued by the bankruptcy court, the court has not ruled on the pending motion. On November 6, 2003, the parties filed a joint stipulation for relief from the stay in order to allow the proceeding to go forward that was promptly granted. PMI cannot estimate at this time the overall exposure for congestion charges for the full term of the contract.

   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., U. S. 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 NYSDEC, sued Niagara Mohawk Power Corporation or NiMo, and 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. On January 11, 2005, the Company reached agreement with the State of New York and NYDEC to settle this matter. The settlement requires the reduction of sulfur dioxide (SO₂) by over 86 percent and nitrogen oxide by over 80 percent in aggregate at the Huntley and Dunkirk plants. To do so, units 63 and 64 at Huntley will be retired after receiving the appropriate regulatory approvals. Units 65 and 66 will be retired eighteen months later. The Company also agreed to limits on the transfer of certain federal SO₂ allowances. NRG Energy is not subject to any penalty as a result of the settlement. Through the end of the decade, the Company expects ongoing compliance with the emissions limits set out in the settlement will be achieved through capital expenditures already planned. This includes conversion to low sulfur western coal at the Huntley and Dunkirk plants that will be completed by Spring 2006. On April 16, 2005, NYDEC filed a motion with the court to enter the consent decree and on April 19, 2005, we filed a supporting motion. We expect the court to enter the consent decree by the third quarter of 2005.

   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 (filed on July 13, 2001)

     NiMo 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. The Company asserted that NiMo is obligated to indemnify it for any related compliance costs associated with resolution of the above referenced NYSDEC enforcement action. On October 18, 2004, the parties reached a confidential settlement, less any related compliance costs associated with resolution of the NYDEC action referenced above.

   Connecticut Light & Power v. NRG Energy, Inc., Federal Energy Regulatory Commission Docket No. EL03-10-000-Station Service Dispute (filed October 9, 2002); Binding Arbitration

     On July 1, 1999, Connecticut Light and Power Company, or CL&P and NRG Energy agreed that NRG Energy would purchase certain CL&P generating facilities. The transaction closed on December 14, 1999, whereupon NRG Energy took ownership of the facilities. CL&P began billing NRG Energy for station service power and delivery services provided to the facilities and NRG Energy refused to pay asserting that the facilities self-supplied their station service needs. On October 9, 2002, Northeast Utilities Services Company, on behalf of itself and CL&P, filed a complaint at FERC seeking an order requiring NRG Energy to pay for station service and deliver services. On December 20, 2002, FERC issued an Order finding that at times when NRG Energy is not able to self-supply its station power needs, there is a sale of station power from a third-party and retail charges apply. CL&P renewed its demand for payment, which was again refused by NRG Energy. In August 2003, the parties agreed to submit the dispute to binding arbitration. The parties each selected one respective arbitrator. A neutral arbitrator cannot be selected until the party-appointed arbitrators have been given a mutually agreed upon description of the dispute, which has yet to occur. Once the neutral arbitrator is selected, a decision is required within 90 days unless otherwise agreed by the parties. The potential loss inclusive of amounts paid to CL&P and accrued could exceed $6 million.

   Niagara Mohawk Power Corporation v. Dunkirk Power LLC, NRG Dunkirk Operations, Inc., Huntley Power LLC, Huntley Power Operations, Inc., Oswego Power LLC and NRG Oswego Operations, Inc., Supreme Court, Erie County, Index No. 1-2000-8681- Station Service Dispute (filed October 2, 2000)

     NiMo seeks to recover damages 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. NiMo claims that NRG Energy failed to pay retail tariff amounts for utility services commencing on or about June 11, 1999, and continuing to September 18, 2000, and thereafter. NiMo alleged breach of contract, suit on account, violation of statutory duty, and unjust enrichment claims. Prior to trial, the parties 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. On October 8, 2002, a Stipulation and Order was filed staying this action pending submission to FERC of some or all of these disputes in the action. The potential loss inclusive of amounts paid to NiMo and accrued is approximately $23.2 million.

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NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES

   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 to the above referenced action filed by NiMo at FERC asserting the same claims and legal theories. On November 19, 2004, FERC denied NiMo’s petition and ruled that the Huntley, Dunkirk and Oswego plants could net their service station obligations over a 30 calendar day period from the day NRG Energy acquired the facilities. In addition, FERC ruled that neither NiMo nor the New York Public Service Commission could impose a retail delivery charge on the NRG facilities because they are interconnected to transmission and not to distribution. On April 22, 2005, FERC denied NiMo’s motion for rehearing. NiMo appealed to the U.S. Court of Appeals for the D.C. Circuit which, on May 12, 2005, ordered this appeal consolidated with several other pending station service disputes involving NiMo. As NiMo has appealed the FERC’s denial, we will not reverse any amounts accrued until such time as it is assumed that our risk of loss has ceased. At this time, we cannot predict the outcome of this matter.

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

     Pursuant to the requirements of Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies,” and related guidance, the Company record reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss is reasonably estimable. Management has assessed each of these matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought and the probability of success. Management’s judgment may, as a result of facts arising prior to resolution of these matters or other factors, prove inaccurate and investors should be aware that such judgment is made subject to the known uncertainty of litigation.

   Expiration of Collective Bargaining Agreement

     Arthur Kill Power LLC employs approximately sixty (60) employees, forty-four (44) of which are represented by Local 3 of the International Brotherhood of Electrical Workers, AFL-CIO. The current collective bargaining agreement covering these represented employees expires June 18, 2005.

15. Regulatory Issues

   New England

     On August 23, 2004, ISO-NE filed its proposal for locational installed capacity, or LICAP, with FERC, which will decide the issue in a litigated proceeding before an administrative law judge. Under the proposal, separate capacity markets would be created for distinct areas of New England, including southwest Connecticut. While the Company views this proposal as a positive development, as it is currently proposed it would not permit us to recover all of the Company’s fixed costs. In response, the Company has submitted testimony which includes an alternative proposal. The hearing is completed and post-trial briefs have been filed. The initial decision by the administrative law judge is scheduled to be issued on June 15, 2005. FERC’s goal is to make a final decision on the precise terms of the LICAP market in the fall of 2005, to be effective January 1, 2006.

     On January 27, 2005, FERC approved the settlement of various reliability must-run, or RMR, agreements between some of our Connecticut generation facilities and ISO-NE. Under the settlement, the Company will receive monthly payments for the Devon 11-14, Montville and Middletown facilities until December 31, 2005, the day before the expected implementation date for LICAP. The settlement also requires the payment of third party maintenance expenses by NEPOOL participants incurred by Devon 11-14, Middletown, Montville, and Norwalk Harbor and are capped at $30 million for the period April 1, 2004 through December 31, 2005. The settlement also approves prior RMR agreements involving Devon 7 and 8, both of which are on deactivated reserves.

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   New York

NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES

     On January 7, 2005, NYISO filed proposed LICAP demand curves for the following capability years: 2005-06, 2006-07 and 2007-08. Under the NYISO proposal, the LICAP price for New York City generation would be $126 per KW year for the capacity year 2006-07. In addition, the NYISO requested a rate of $67 per KW year for the capacity year 2006-07 for the rest of New York State excluding Long Island. On January 28, 2005, the Company filed a protest at FERC asserting the LICAP price for New York City for 2006-07 should be at least $140 per KW year. On April 21, 2005 FERC accepted the proposed demand curve with some modification. It is anticipated that capacity prices for New York state, including New York City and Long Island, will probably increase by $1 per KW year. The FERC’s modification should increase the capacity prices in New York City but the existing In-City mitigation measures would prevent us from obtaining these higher prices.

     Our New York City generation is presently subject to price mitigation in the installed capacity market. When the capacity market is tight, the price we receive is limited by the mitigation price. However when the New York City capacity market is not tight, such as during the winter season, the proposed demand curve price levels should increase our revenues from capacity sales.

16. Income Taxes

     The Company is included in the consolidated income 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 income tax provisions, as if the Company had prepared separate filings. The Company’s ultimate parent, NRG Energy, does not have a tax allocation agreement with its subsidiaries. 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 provision (benefit) for income taxes consists of the following:

	Reorganized Company						Predecessor Company
				Period from			Period from
	For the Year			December 6,			January 1,			For the Year
	Ended			2003 to			2003 to			Ended
	December 31,			December 31,			December 5,			December 31,
	2004			2003			2003			2002
	(In thousands of dollars)
Current
Federal	$	7,089		$	2,957		$	11,390		$	12,094
State		2,835			1,183			4,555			4,837
		9,924			4,140			15,945			16,931
Deferred
Federal		82,030			229			(89,837	)		(9,622	)
State		32,810			91			(35,932	)		(3,849	)
		114,840			320			(125,769	)		(13,471	)
Total income tax expense (benefit)	$	124,764		$	4,460		$	(109,824	)	$	3,460
Effective tax rate		43.0	%		43.2	%		43.0	%		89.1	%

28

NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES

     The pre-tax income (loss) was as follows:

	Reorganized Company				Predecessor Company
			For the		For the
			Period from		Period from
	For the Year		December 6,		January 1,			For the Year
	Ended		2003 to		2003 to			Ended
	December 31,		December 31,		December 5,			December 31,
	2004		2003		2003			2002
	(In thousands of dollars)
U.S.	$	289,892	$	10,306	$	(255,511	)	$	3,885

     The components of the net deferred income tax liabilities (assets) were:

	Reorganized Company
	December 31,		December 31,
	2004		2003
	(In thousands of dollars)
Deferred tax liabilities
Investments in projects	$	3	$	3
Emissions credits		69,535		90,722
Net unrealized gain on mark to market transactions		22,099		—
Other		6,416		1,982
Total deferred tax liabilities		98,053		92,707
Deferred tax assets
Deferred compensation, accrued vacation and other reserves		3,722		3,236
Difference between book and tax basis of contracts		1,125		—
Development costs		82		116
Intangibles amortization (other than goodwill)		7,418		8,163
Property		12,786		121,863
Congestion accrual		48,035		48,035
Other		55		2,406
Net deferred tax assets		73,223		183,819
Net deferred tax liabilities (assets)	$	24,830	$	(91,112	)

     The net deferred tax liabilities (assets) consists of:

	Reorganized Company
	December 31,		December 31,
	2004		2003
	(In thousands of dollars)
Current deferred tax liabilities	$	260	$	453
Noncurrent deferred tax liabilities (assets)		24,570		(91,565	)
Net deferred tax liabilities (assets)	$	24,830	$	(91,112	)

     In assessing the realizabilty of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The realization of deferred tax assets is dependent upon the generation of taxable income in future periods. Management considers both positive and negative evidence, projected operating income and capital gains, and available tax planning strategies in making this assessment. Based upon projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Company will realize the benefits of these net deferred tax assets as of December 31, 2004.

     In connection with the Company’s emergence from bankruptcy, the 2003 net operating loss carryforward was effectively increased as a result of the Company’s election in 2004 to reduce the tax basis of property on a going forward basis. This election was made in 2004 in connection with tax planning strategies for future periods and accordingly was recorded subsequent to the period ended December 31, 2003.

     During 2004, the Company utilized the full amount of U.S. net operating losses carryforward of $260.0 million. There is no net carryforward amount available as of December 31, 2004.

     The effective income tax rates of continuing operations differ from the statutory federal income tax rate of 35% as follows:

29

NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES

	Reorganized Company								Predecessor Company
					For the				For the
					Period from				Period from
	For the Year				December 6,				January 1,					For the Year
	Ended				2003 to				2003 to					Ended
	December 31,				December 31,				December 5,					December 31,
	2004				2003				2003					2002
	(In thousands of dollars)
Income (loss) before taxes	$	289,892			$	10,306			$	(255,511	)			$	3,885
Tax at 35%		101,462	35.0	%		3,607	35.0	%		(89,429	)	35.0	%		1,360	35.0	%
State taxes (net of federal benefit)		23,169	8.0	%		828	8.0	%		(20,395	)	8.0	%		643	16.6	%
Other		133	0.0	%		25	0.2	%		—		0.0	%		1,457	37.5	%
Income tax expense (benefit)	$	124,764	43.0	%	$	4,460	43.2	%	$	(109,824	)	43.0	%	$	3,460	89.1	%

30

EX-99.2

EXHIBIT 99.2

NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

CONSOLIDATED FINANCIAL STATEMENTS

At December 31, 2004 and 2003,
and for the Year Ended December 31, 2004,
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

1

NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

INDEX

	Page
Reports of Independent Registered Public Accounting Firms		3
Consolidated Balance Sheets at December 31, 2004 and 2003		6
Consolidated Statements of Operations for the year ended December 31, 2004, 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		7
Consolidated Statements of Member’s Equity for the year ended December 31, 2004, 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		8
Consolidated Statements of Cash Flows for the year ended December 31, 2004, 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		9
Notes to Consolidated Financial Statements		10
Report of Independent Registered Public Accounting Firm on Financial Statement Schedule		33
Financial Statement Schedule		34

2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Member of
NRG South Central Generating LLC

     We have audited the accompanying consolidated balance sheet of NRG South Central Generating LLC and its subsidiaries as of December 31, 2004, and the related consolidated statements of operations, member’s equity, and cash flows for the year then ended. In connection with our audit of the consolidated financial statements, we have also audited the financial statement schedule “Schedule II Valuation and Qualifying Accounts.” These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audit.

     We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

     In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of NRG South Central Generating LLC and its subsidiaries as of December 31, 2004, and the results of their operations and their cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/S/	KPMG LLP
	KPMG LLP

Philadelphia, Pennsylvania
May 27, 2005

3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Member 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 (“Reorganized Company”) at 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 audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 audit provides a reasonable basis for our opinion.

     As discussed in Notes 1 and 2 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

4

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Member of
NRG South Central Generating LLC

     In our opinion, the accompanying consolidated statements of operations, of member’s equity, and of cash flows present fairly, in all material respects, the results of operations and cash flows of NRG South Central Generating LLC and its subsidiaries (“Predecessor Company”) for the period from January 1, 2003 to December 5, 2003 and for the year 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). 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 Notes 1 and 2 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

5

NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	Reorganized Company
	December 31,		December 31,
	2004		2003
	(In thousands of dollars)
ASSETS
Current assets
Cash and cash equivalents	$	19,861	$	4,612
Restricted cash		—		99
Accounts receivable, net of allowance for doubtful accounts of $13 and $13, respectively		40,231		37,080
Accounts receivable — affiliates		—		3,328
Notes receivable		—		584
Inventory		33,972		35,098
Derivative instruments valuation		205		—
Prepayments and other current assets		8,000		7,079
Total current assets		102,269		87,880
Property, plant and equipment, net of accumulated depreciation of $64,921 and $2,561, respectively		883,079		914,941
Decommissioning fund investments		4,954		4,809
Intangible assets, net of amortization of $13,751 and $787, respectively		81,374		120,992
Other assets		871		3,111
Total assets	$	1,072,547	$	1,131,733
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Note payable — affiliate	$	1,425	$	81,673
Accounts payable		5,870		10,476
Accounts payable — affiliates		17,020		—
Accrued interest — affiliate		620		7,434
Other current liabilities		18,085		18,525
Total current liabilities		43,020		118,108
Note payable-affiliate		76,672		—
Out of market contracts		318,664		341,004
Other long-term obligations		3,899		9,789
Total liabilities		442,255		468,901
Commitments and contingencies
Member’s equity		630,292		662,832
Total liabilities and member’s equity	$	1,072,547	$	1,131,733

The accompanying notes are an integral part of these consolidated financial statements.

6

NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Reorganized Company						Predecessor Company
				For the			For the
				Period from			Period from
	For the Year			December 6,			January 1,			For the Year
	Ended			2003 to			2003 to			Ended
	December 31,			December 31,			December 5,			December 31,
	2004			2003			2003			2002
	(In thousands of dollars)
Revenues	$	418,145		$	26,608		$	356,535		$	399,866
Operating costs		271,737			17,514			236,216			262,361
Depreciation and amortization		62,458			2,561			33,988			35,964
General and administrative expenses		22,732			1,901			10,687			7,948
Reorganization items		974			104			31,120			—
Restructuring and impairment charges		2,910			—			—			139,929
Income (loss) from operations		57,334			4,528			44,524			(46,336	)
Other income (expense), net		725			99			1,475			923
Losses of unconsolidated affiliates		—			—			—			(3,146	)
Write downs and losses on sale of equity investments		—			—			—			(48,375	)
Interest expense		(8,709	)		(4,133	)		(73,968	)		(74,940	)
Income (loss) before income taxes		49,350			494			(27,969	)		(171,874	)
Income tax expense (benefit)		20,171			201			—			(39,789	)
Net income (loss)	$	29,179		$	293		$	(27,969	)	$	(132,085	)

The accompanying notes are an integral part of these consolidated financial statements.

7

NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY

					Member’s			Accumulated			Total
	Member’s				Contributions/			Net Income			Member’s
	Units		Amount		Distributions			(Loss)			Equity
	(In thousands of dollars)
Balances at December 31, 2001 (Predecessor Company)		1,000	$	1	$	384,150		$	21,573		$	405,724
Net loss		—		—		—			(132,085	)		(132,085	)
Contribution from member		—		—		50,011			—			50,011
Balances at December 31, 2002 (Predecessor Company)		1,000		1		434,161			(110,512	)		323,650
Net loss		—		—		—			(27,969	)		(27,969	)
Contribution from member		—		—		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 member		—		—		632,330			—			632,330
Net income		—		—		—			293			293
Balances at December 31, 2003 (Reorganized Company)		1,000	$	1	$	662,538		$	293		$	662,832
Net income		—		—		—			29,179			29,179
Distribution to member		—		—		(32,247	)		(29,472	)		(61,719	)
Balances at December 31, 2004 (Reorganized Company)		1,000	$	1	$	630,291		$	—		$	630,292

The accompanying notes are an integral part of these consolidated financial statements.

8

NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

	Reorganized Company						Predecessor Company
				For the			For the
				Period from			Period from
	For the Year			December 6,			January 1,			For the Year
	Ended			2003 to			2003 to			Ended
	December 31,			December 31,			December 5,			December 31,
	2004			2003			2003			2002
	(In thousands of dollars)
Cash flows from operating activities
Net income (loss)	$	29,179		$	293		$	(27,969	)	$	(132,085	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Equity in losses of unconsolidated affiliates in excess of distributions		—			—			—			3,146
Depreciation and amortization		62,458			2,561			33,988			35,964
Deferred income taxes		20,171			201			—			(39,789	)
Loss on sale of equity method investments		—			—			—			48,375
Reorganization items		—			—			9,141			—
Special charges		—			—			4,367			—
Amortization of intangibles		12,964			—			—			—
Amortization of debt issuance costs		—			—			1,557			1,103
Amortization of debt discount		2,530			182			—			—
Amortization of out-of-market power contracts		(21,765	)		(2,199	)		—			—
Loss on disposal of fixed assets		268			—			—			—
Asset impairment		493			—			—			138,578
Unrealized (gain) loss on derivatives		—			(994	)		—			5
Changes in assets and liabilities
Accounts receivable		(3,151	)		673			8,585			(2,216	)
Inventory		1,126			5,325			16,394			(11,448	)
Prepayments and other current assets		(921	)		1,568			(5,411	)		(609	)
Accounts payable		(4,606	)		(4,803	)		(4,838	)		(6,806	)
Accounts receivable/payable — affiliates		17,709			1,423			(131,787	)		58,220
Accrued interest		(6,814	)		(14,787	)		(33,192	)		35,474
Other current assets and liabilities		(440	)		(14,312	)		21,227			2,160
Changes in other assets and liabilities		2,053			2,222			(285	)		559
Net cash provided by (used in) operating activities		111,254			(22,647	)		(108,223	)		130,631
Cash flows from investing activities
Capital expenditures		(31,357	)		(329	)		(8,610	)		(12,231	)
Increase (decrease) in notes receivable		584			916			1,500			(3,000	)
Decrease in trust funds		(145	)		—			—			—
Decrease (increase) in restricted cash		99			133,694			(24,457	)		(109,336	)
Net cash (used in) provided by investing activities		(30,819	)		134,281			(31,567	)		(124,567	)
Cash flows from financing activities
Contribution by member		—			632,330			150,878			48,000
Distribution to member		(61,719	)		—			—			—
Net payments on revolving credit facility		—			—			—			(40,000	)
Repayments of long-term borrowings		—			(750,750	)		—			(12,750	)
Repayment of note payable — affiliate		(3,467	)		—			—			(1,862	)
Checks in excess of cash		—			—			—			(2,350	)
Net cash (used in) provided by financing activities		(65,186	)		(118,420	)		150,878			(8,962	)
Net change in cash and cash equivalents		15,249			(6,786	)		11,088			(2,898	)
Cash and cash equivalents
Beginning of period		4,612			11,398			310			3,208
End of period	$	19,861		$	4,612		$	11,398		$	310
Supplemental disclosures of cash flow information
Cash paid for interest	$	—		$	29,999		$	105,785		$	39,466
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

The accompanying notes are an integral part of these consolidated financial statements.

9

NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization

     NRG South Central Generating LLC, or NRG South Central or the Company, is a wholly owned subsidiary of NRG Energy, Inc., or NRG Energy. NRG South Central owns 100% of Louisiana Generating LLC, or Louisiana Generating; NRG New Roads Holding LLC, or New Roads; NRG Sterlington Power LLC, or Sterlington; Big Cajun I Peaking Power LLC, or Big Cajun Peaking; and NRG Bayou Cove LLC, or Bayou Cove.

     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.

     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, or the 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 LLC 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 Cajun facilities’ power purchase agreements, with any excess power and capacity being marketed by NRG Power Marketing.

     NRG Bayou Cove LLC was formed in September 2001 for the purpose of developing, owning and operating, through Bayou Cove Peaking Power LLC (which owns 100% of the membership interest), an approximately 320 MW gas-fired peaking generating facility located near Jennings, Louisiana. The Bayou Cove facility was completed and began commercial operation in the summer of 2002 and all of its power and capacity are marketed by NRG Power Marketing.

     From May 14, 2003 to December 23, 2003, NRG Energy and a number of its subsidiaries, including South Central, undertook a comprehensive reorganization and restructuring under chapter 11 of the United States Bankruptcy Code. The Northeast/South Central Plan of Reorganization, relating to the Company, the NRG Northeast Generating LLC subsidiaries and the other South Central subsidiaries, 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.

     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 and Basis of Presentation

     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 Statement of Position 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code”, or SOP 90-7.

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NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

     For financial reporting purposes, close of business on December 5, 2003, represents the date of the Company’s emergence from bankruptcy because that is the date of emergence for the ultimate parent company, NRG Energy. As previously stated, the Company emerged from bankruptcy on December 23, 2003. The accompanying financial statements reflect the impact of the Company’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, pre-emergence from bankruptcy
	The Company’s operations prior to December 6, 2003
“Reorganized Company”	The Company, post-emergence from bankruptcy
	The Company’s operations, December 6, 2003 - December 31, 2004

     The consolidated financial statements include our accounts and operations and those of our subsidiaries in which we have a controlling interest. All significant intercompany transactions and balances have been eliminated in consolidation. Accounting policies of all of our operations are in accordance with 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 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 percent of the voting shares of the emerging entity. NRG Energy met these requirements and adopted Fresh Start reporting resulting in the creation of a new reporting entity designated as Reorganized NRG. 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.

     The bankruptcy court issued a confirmation order approving 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. The Xcel Energy settlement agreement was entered into on December 5, 2003. NRG Energy 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.

     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, or SFAS No. 109, “Accounting for Income Taxes”. The net effect of all Fresh Start adjustments resulted in a gain of $3.9 billion (comprised of a $4.1 billion gain from continuing operations and a $0.2 billion loss from discontinued operations), 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 and push down accounting 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 NRG Energy’s 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 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. The reorganization value of approximately $9.1 billion was determined by adding the reorganized equity value of

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NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

$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.

     A separate plan of reorganization was filed for South Central 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, NRG Energy accounted for these entities as if they had emerged from bankruptcy at the same time that NRG Energy emerged, as it is believed that NRG Energy continued to maintain control over the South Central facilities throughout the bankruptcy process.

     Due to the adoption of Fresh Start upon NRG Energy’s emergence from bankruptcy and the impact of push down accounting, the Reorganized Company’s 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.

   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 to satisfy the requirements of certain debt agreements and funds held within the Company’s projects that are restricted in their use. These funds are used to pay for current operating expenses and current debt service payments, per the restrictions of the debt agreements.

   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 following 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.

Facilities and equipment	1 to 35 years
Office furnishings and equipment	1 to 5 years

   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 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 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.

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NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

   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 year ended December 31, 2004, 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.

   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 whenever events or changes in circumstances indicate carrying values may not be recoverable.

     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.

   Out of Market Contracts

     As part of push down accounting, the Company recognized liabilities for executory contracts, or power sales agreements, related to the sale of electric capacity and energy in future periods, where the fair value was determined to be significantly out of market 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 determined as of the Fresh Start date. 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, revenue is recognized as products are delivered. Where bilateral markets exist and the Company physically delivers electricity from its plants, we record revenue on a gross basis. 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 is reflected as equity in earnings of unconsolidated affiliates.

   Power Marketing Activities

     Certain of the subsidiaries of NRG South Central have entered into 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 enables the affiliate to engage in forward purchases, sales and hedging transactions to manage the Company’s electricity price exposure. See Note 12 – Related Party Transactions.

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NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

   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 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 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 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.

   Credit Risk

     Credit risk relates to the risk of loss resulting from non-performance or non-payment by counter-parties pursuant to the terms of their contractual obligations. NRG Energy monitors and manages the credit risk of its affiliates including the Company and its subsidiaries, through credit policies which include an (i) established credit approval process, (ii) daily monitoring of counter-party credit limits, (iii) the use of credit mitigation measures such as margin, collateral, credit derivatives or prepayment arrangements, (iv) the use of payment netting agreements and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counter-party. Risk surrounding counter-party performance and credit could ultimately impact the amount and timing of expected cash flows. NRG Energy has credit protection within various agreements to call on additional collateral support if necessary.

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

   Fair Value of Financial Instruments

     The carrying amounts of cash and cash equivalents, restricted cash, receivables, accounts payables, and accrued liabilities approximate fair value because of the short maturity of these instruments. The fair value of note payable – affiliate 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, disclosure of contingent 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.

   Recent Accounting Pronouncements

     In November 2004, the FASB issued SFAS No. 151, “Inventory Costs- an amendment of ARB No. 43, Chapter 4”. This statement amends the guidance in ARB No. 43, Chapter 4, “Inventory Pricing”, and requires that idle facility expense, excessive spoilage, double freight, and rehandling costs be recognized as current-period charges regardless of whether they meet the criterion of “so abnormal” established by ARB No. 43. SFAS No. 151 is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The Company is currently

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NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

in the process of evaluating the potential impact that the adoption of this statement will have on the Company’s consolidated financial position and results of operations.

     In December 2004, the FASB issued two FASB Staff Positions, or FSPs, regarding the accounting implications of the American Jobs Creation Act of 2004 related to (1) the deduction for qualified domestic production activities (FSP FAS 109-1) and (2) the one-time tax benefit for the repatriation of foreign earnings (FSP FAS 109-2). In FSP FAS 109-1, Application of FASB Statement No. 109, Accounting for Income Taxes,” to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004, the Board decided that the deduction for qualified domestic production activities should be accounted for as a special deduction under FASB Statement No. 109, “Accounting for Income Taxes” and rejected an alternative view to treat it as a rate reduction. Accordingly, any benefit from the deduction should be reported in the period in which the deduction is claimed on the tax return. FSP FAS 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004”, addresses the appropriate point at which a company should reflect in its financial statements the effects of the one-time tax benefit on the repatriation of foreign earnings. Because of the proximity of the Act’s enactment date to many companies’ year-ends, its temporary nature, and the fact that numerous provisions of the Act are sufficiently complex and ambiguous, the Board decided that absent additional clarifying regulations, companies may not be in a position to assess the impact of the Act on their plans for repatriation or reinvestment of foreign earnings. Therefore, the Board provided companies with a practical exception to FAS 109’s requirements by providing them additional time to determine the amount of earnings, if any, that they intend to repatriate under the Act’s beneficial provisions. The Board confirmed, however, that upon deciding that some amount of earnings will be repatriated, a company must record in that period the associated tax liability, thereby making it clear that a company cannot avoid recognizing a tax liability when it has decided that some portion of its foreign earnings will be repatriated. The Company is currently in the process of evaluating the potential impact that the adoption of FSP FAS 109-1 will have on our consolidated financial position and results of operations. The Company does not believe that the potential adoption of FSP 109-2 will have a material impact on our consolidated financial position and results of operation.

     In March 2005, the Financial Accounting Standards Board (FASB) issued Interpretation No. 47 (FIN 47) to Financial Accounting Standard No. 143 (SFAS No. 143) governing the application of Asset Retirement Obligations. FIN 47 clarifies that the term “conditional asset retirement obligation” as used in SFAS 143. SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional but there may remain some uncertainty as to the timing and/or method of settlement. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred — generally upon acquisition, construction, or development and/or through the normal operation of the asset. SFAS No. 143 acknowledges that in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation. FIN 47 clarifies when the company would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective for fiscal years ending after December 15, 2005 and we are currently evaluating the impact of this guidance.

3. Emergence from Bankruptcy and Fresh Start Reporting

     In accordance with the requirements of SFAS No. 141 “Business Combinations” and push down accounting, the Company’s fair value of $30.2 million was allocated, as of the Fresh Start date, 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 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.

     The effects of the push down accounting adjustments on the Company’s condensed consolidated balance sheet as of December 5, 2003 were as follows:

	Predecessor Company						Reorganized Company
	December 5,			Push Down			December 6,
	2003			Adjustments			2003
			(in thousands)
Current assets	$	245,812		$	(7,547)		$	238,265
Non-current Assets		1,128,558			(81,708	)		1,046,850
Total Assets	$	1,374,370		$	(89,255	)	$	1,285,115
Current Liabilities		926,505			(24,000	)		902,505
Non-current liabilities		1,306			351,095	)		352,401
		927,811			327,095			1,254,906
Member’s Equity		446,559			(416,350	)		30,209
Total Liabilities and Member’s Equity	$	1,374,370		$	(89,255	)	$	1,285,115

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NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

4. Other Charges

     Reorganization items and restructuring and impairment charges included in the consolidated statement of operations include the following:

	Reorganized Company				Predecessor Company
			For the		For the
			Period from		Period from
	For the Year		December 6,		January 1,		For the Year
	Ended		2003 to		2003 to		Ended
	December 31,		December 31,		December 5,		December 31,
	2004		2003		2003		2002
			(In thousands of dollars)
Reorganization items	$	974	$	104	$	31,120	$	—
Restructuring and impairment charges		2,910		—		—		139,929
	$	3,884	$	104	$	31,120	$	139,929

   Reorganization Items

     For the period from January 1, 2003 to December 5, 2003, 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 refinancing transaction completed in December 2003. Both items were expensed in November 2003, as they were determined to be an allowed claim at that time. The Company also incurred legal and advisor fees of $11.5 million. The following table provides the detail of the types of costs incurred. There were no reorganization items in 2002.

					Predecessor
	Reorganized Company				Company
			For the		For the
			Period from		Period from
	For the Year		December 6,		From January 1,
	Ended		2003 to		2003 to
	December 31,		December 31,		December 5,
	2004		2003		2003
	(In thousands of dollars)
Reorganization items
Deferred financing costs	$	—	$	—	$	9,141
Pre-payment charge		—		—		11,261
Legal and advisor fees related to bankruptcy		134		104		11,494
Settlement of pre-petition claims		840		—		—
Interest earned on accumulated cash		—		—		(776	)
Total reorganization items	$	974	$	104	$	31,120

   Restructuring and Impairment Charges

     In January 2004, the Company closed the South Central regional office in Baton Rouge, Louisiana and offered it for sale. During the fourth quarter of 2004, the Company recorded a charge of $0.5 million related to the impairment in the net realizable value based on two offers received. In June 2004, the Company received a proposal to sell certain turbine equipment of its New Roads subsidiary and recorded an impairment charge of $1.7 million based on the proposed sales price. The offer was subsequently withdrawn and in September 2004, an additional impairment charge of $0.7 million relative to the turbine equipment was recorded.

     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.

     In addition to asset impairment charges, in 2002, 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.

5. Inventory

     Inventory, which is valued at the lower of weighted average cost or market, consists of:

	Reorganized Company
	December 31,		December 31,
	2004		2003
	(In thousands of dollars)
Coal	$	24,988	$	26,108
Spare parts		8,030		8,207
Fuel oil		954		783
Total inventory	$	33,972	$	35,098

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NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

6. Property, Plant and Equipment

     The major classes of property, plant and equipment were as follows:

	Average	Reorganized Company
	Remaining	December 31,			December 31			Depreciable
	Useful Life	2004			2003			Lives
	(In thousands of dollars)
Land		$	30,935		$	30,935
Facilities, machinery and equipment	17 years		915,122			885,656		1-35 years
Office furnishings and equipment	3 years		—			582		1-5 years
Construction in progress			1,943			329
Accumulated depreciation			(64,921	)		(2,561	)
Property, plant and equipment, net		$	883,079		$	914,941

7. Asset Retirement Obligations

     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 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.

     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, the period from December 6, 2003 to December 31, 2003, and the year ended December 31, 2004. The asset retirement obligations are 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 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 fresh start reporting on December 6, 2003, equal to 500 to 600 basis points.

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NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

	Reorganized Company
			Accretion for
			Period				Accretion
	Beginning		December 6,		Ending		for Year		Ending
	Balance		2003 to		Balance		Ended		Balance
	December 6,		December 31,		December 31,		December 31,		December 31,
	2003		2003		2003		31, 2004		2004
	(In thousands of dollars)
Asset retirement obligations	$	2,623	$	15	$	2,638	$	184	$	2,822

	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

8. Intangible Assets

   Reorganized Company

     Upon adoption of Fresh Start and application of push down accounting, the Company established certain intangible assets for power sales agreements and plant emission allowances. These intangible assets will be amortized over their respective lives based on a straight-line or units of production basis.

     Power sales agreements are amortized as a reduction to revenue over the terms and conditions of each contract. The remaining amortization period for the power sales agreements is three years. Emission allowances are amortized as additional fuel expense based upon the actual level of emissions from the respective plants through 2023. Aggregate amortization recognized for the year ended December 31, 2004 was $13.0 million. Amortization expense recognized during the period from December 6, 2003 to December 31, 2003 was $0.8 million related only to the power sales agreements. No emission allowances were used during 2003. The annual aggregate amortization expense for each of the five succeeding years is expected to approximate $9.3 million in years one through three, and $4.4 million in years four and five for both the power sales agreements and emission allowances. The expected annual amortization of these amounts is expected to change as the Company relieves the tax valuation allowance as explained below.

     For the year ended December 31, 2004, the Company reduced its tax valuation allowance by $20.2 million, and in accordance with SOP 90-7, recorded a corresponding reduction related to the Company’s intangible assets. As a result of the recognition of a deferred tax asset valuation allowance in connection with push down accounting, any future benefits from reducing the valuation allowance should first reduce intangible assets until exhausted, and thereafter be recorded as a direct addition to paid-in capital. Intangible assets were also reduced by $6.5 million related to a true-up of certain tax evaluations.

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NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

Intangible assets consisted of the following:

	Power Sale			Emission
	Agreements			Allowances			Total
Balances as of December 31, 2003	$	27,013		$	93,979		$	120,992
Tax valuation adjustment		(4,503	)		(15,668	)		(20,171	)
Amortization		(7,972	)		(4,992	)		(12,964	)
Other adjustments		(1,115	)		(5,368	)		(6,483	)
Balances as of December 31, 2004	$	13,423		$	67,951		$	81,374

Predecessor Company

     The Company had intangible assets that were amortized and consisted of service contracts that were terminated at bankruptcy. For the period from January 1, 2003 to December 5, 2003, and for the year ended December 31, 2002, the Company recorded approximately $0 and $123,000 of amortization expense, respectively.

9. Note Payable — Affiliate

     NRG South Central’s note payable — affiliate consists of the following:

	Reorganized Company
	December 31,			December 31,
	2004			2003
	(In thousands of dollars)
NRG Peaker — Bayou Cove — note payable affiliate due 2019 — 6.673%	$	99,385		$	105,491
Unamortized fair value adjustment		(21,288	)		(23,818	)
Total note payable — affiliate		78,097			81,673
Less current maturities		1,425			—
	$	76,672		$	81,673

     On June 18, 2002, NRG Peaker Finance Company LLC, or 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, or Bayou Cove, Big Cajun I Peaking Power LLC, or Big Cajun Peaking, NRG Rockford LLC and Rockford II LLC and NRG Sterlington Power LLC, or Sterlington. Three of these entities, Bayou Cove, Big Cajun Peaking, and Sterlington, are wholly owned non-guarantor 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, or 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, 2004 and December 31, 2003, Bayou Cove, had an affiliate loan outstanding in the amount of $99.4 million and $105.5 million respectively, 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 a result of a downgrade in NRG Energy’s credit rating, NRG Peaker bonds were in default as of December 31, 2003 and were classified as current on the Company’s balance sheet. In January 2004, terms of the financing arrangement were restructured, at which time NRG Energy posted a $36.2 million letter of credit under its cash-collateralized letter of credit facility and the NRG Peaker bonds were no longer in default. As a result, the bonds and associated note payable-affiliate were re-classified as long-term.

     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

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NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

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.

     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 a contingent guarantee by NRG Energy, 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, 2004 and 2003, the unamortized debt discounts recorded in debt were $64.4 million and $72.1 million, respectively. Approximately $21.3 million and $23.8 million of these amounts relate to Bayou Cove at December 31, 2004 and 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% (3.53% at December 31, 2004) 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. 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, 2004. The agreement expires in June 2019. There is no swap agreement between the Company and NRG Peakers.

10. Accounting for Derivative Instruments and Hedging Activity

     SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” as amended by SFAS No. 137, SFAS No. 138 and SFAS No. 149 requires the Company to recognize all derivative instruments on the balance sheet as either assets or liabilities and measure them at fair value each reporting period. If certain conditions are met, the Company may be able to designate derivatives as cash flow hedges and defer the effective portion of the change in fair value of the derivatives in Accumulated Other Comprehensive Income (OCI) and subsequently recognize in earnings when the hedged items impact income. The ineffective portion of a cash flow hedge is immediately recognized in income.

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

     For derivatives that are neither designated as cash flow hedges or do not qualify for hedge accounting treatment, the changes in the fair value will be immediately recognized in earnings.

     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, 2004, the Company had various commodity contracts extending through December 2005.

   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, NRG Power Marketing 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 year ended December 31, 2004, 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, the Company recognized no gain or loss due to ineffectiveness of commodity cash flow hedges.

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NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

   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, 2004 and December 31, 2003, respectively, there were no such instruments outstanding.

   Statement of Operations

     The following table summarizes the effects of SFAS No. 133 on the Company’s statements of operations for the year ended December 31, 2004, 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:

	Reorganized Company						Predecessor Company
				For the			For the
				Period from			Period from
	For the Year			December 6,			January 1,			For the Year
	Ended			2003 to			2003 to			Ended
	December 31,			December 31,			December 5,			December 31,
	2004			2003			2003			2002
	(In thousands of dollars)
Revenues	$	(227	)	$	(72	)	$	(112	)	$	92
Cost of operations		(23	)		—			135			(97	)
Total statement of operations impact before tax	$	(250	)	$	(72	)	$	23		$	(5	)

     For the year ended December 31, 2004, 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, 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 year ended December 31, 2004, the period from December 6, 2003 to December 31, 2003, and for the year ended December 31, 2002 by $250,000, $72,000, and $5,000, respectively. The Company’s earnings were increased for the period from January 1, 2003 to December 5, 2003 by $23,000 associated with the changes in 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
	December 31, 2004				December 31, 2003
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
	(In thousands of dollars)
Cash and cash equivalents	$	19,861	$	19,861	$	4,612	$	4,612
Restricted cash		—		—		99		99
Accounts receivable		40,231		40,231		37,080		37,080
Accounts receivable — affiliates		—		—		3,328		3,328
Notes receivable		—		—		584		584
Decommissioning funds		4,954		4,954		4,809		4,809
Note payable — affiliate		78,097		78,097		81,673		81,673
Accounts payable		5,870		5,870		10,476		10,476
Accounts payable — affiliates		17,020		17,020		—		—

     For cash and cash equivalents, restricted cash, accounts receivable and accounts payable, 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 note payable — affiliate is estimated based on the quoted

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NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

market prices for these issues with similar credit quality. Decommissioning fund investments are comprised of various U.S. debt securities and are carried at amortized cost, which approximates their fair value.

12. Related Party Transactions

     Certain of the subsidiaries of the Company have entered into energy marketing services agreements with NRG Power Marketing Inc., or NRG Power Marketing, a wholly owned subsidiary of NRG Energy. The agreements are effective for a period of ten years, beginning January 4, 2004 and extend for additional one-year terms unless terminated upon at least 90-days written notice prior to the end of any such term. The agreement between Louisiana Generating LLC and NRG Power Marketing Inc. is effective for consecutive one-year terms until terminated by either party upon 90 days written notice before the end of any such term. Under the agreements, NRG Power Marketing will (i) have the exclusive right to manage, market and sell all power not otherwise sold or committed to 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’s 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.

     Certain subsidiaries of the Company have entered into operation and maintenance agreements with NRG Operating Services, Inc., or NRG Operating Services, a wholly owned subsidiary of NRG Energy. The agreements are perpetual in term until terminated in writing by the subsidiary or until earlier terminated upon an event of default. Under the agreement, at the request of the subsidiary, NRG Operating Services manages, oversees and supplements the operation and maintenance of its facilities. These costs are reflected in operating costs in the statement of operations.

     For the year ended December 31, 2004, 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, 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.

     For the year ended December 31, 2004, 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, the Company incurred approximately $10.4 million, $1.2 million, $3.4 million and $0.8 million, respectively, for corporate support and services. The amounts paid for the year ended December 31, 2004 reflect an overall increase in corporate level general and administrative expenses. Corporate general, administrative and development expenses increase in 2004 due to higher legal fees, increased audit costs and increased consulting costs due to NRG Energy’s Sarbanes-Oxley implementation. The method of allocating these costs remained the same from the prior years.

     At December 31, 2004, the Company had an accounts payable — affiliates balance of approximately $17.0 million. At December 31, 2003, the Company had an accounts receivable — affiliates balance of $3.3 million. These balances are settled on a periodic basis and are due to or from multiple entities which are wholly owned subsidiaries of NRG Energy Inc, the parent company of South Central Generating LLC.

     In August 2004, NRG Energy entered into a contract to purchase 1,540 aluminum railcars from Johnston America Corporation to be used for the transportation of low sulfur coal from Wyoming to NRG Energy’s coal burning generating plants, including the Cajun Facilities. On February 18, 2005, NRG Energy entered into a ten-year operating lease agreement with GE Railcar Services Corporation, or GE, for the lease of 1,500 railcars and delivery commenced in February 2005. NRG Energy assigned certain of rights and obligations for 1,500 railcars under the purchase agreement with Johnston America to GE. Accordingly, the railcars which NRG Energy lease from GE under the arrangement described above will be purchased by GE from Johnston America in lieu of NRG Energy’s purchase of those railcars.

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NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

13. Sales to Significant Customers

     The Company derives revenues from two significant customers:

	Reorganized Company						Predecessor Company
				For the			For the
				Period			Period
	For the Year			December 6,			January 1,			For the Year
	Ended			2003 to			2003 to			Ended
	December 31,			December 31,			December 5,			December 31,
	2004			2003			2003			2002
	(Percent of total revenues)
Sales to:
Southwest Louisiana Electric Membership Corporation		17.1	%		17.6	%		18.3	%		16.9	%
Dixie Electric Membership Corporation		16.8	%		17.5	%		17.5	%		15.9	%

     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 74.0%, 86.7%, 84.9%, and 80.8%, respectively, of the Company’s total revenues during the year ended December 31, 2004, 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.

14. 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 $0.4 million, $27,000, $0.5 million, and $0.5 million for the year ended December 31, 2004, 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 payments under these leases for the years ending after December 31, 2004, are as follows:

	Total
	(In thousands
	of dollars)
2005		268
2006		150
2007		57
2008		20
2009		20
Thereafter		110
	$	625

   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 out-of-market

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NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

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 December 31, 2004 and 2003 was $318.7 million and $341.0 million, respectively. During the year ended December 31, 2004 and for the period from December 6, 2003 to December 31, 2003, approximately $21.8 million and $1.7 million, respectively, 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 six 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.

   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 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 data 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

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NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

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/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, 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.

     During contract year six, Louisiana Generating will establish a rate fund equal to $18 million times the ratable share of Form B distribution cooperative’s aggregate 1998 demand to total 1998 demand. Based on the one existing Form B customer, the fund will be approximately $720,000; this amount may increase if additional cooperatives join the Form B cooperatives.

   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 a 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 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, or SWEPCO, one agreement with South Mississippi Electric Power Association, or SMEPA, and one agreement with Municipal Energy Agency of Mississippi, or MEAM.

     The SWEPCO Operating Reserves and Off-Peak Power Sale Agreement, terminates on December 31, 2007. The agreement requires Louisiana Generating 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 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.

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NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

     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 was fixed through May 31, 2004, and increases for the period from 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 Agreements

     Louisiana Generating has 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. In December 2004, Louisiana Generating extended the coal purchase contract though 2007. 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 SO2 emission allowances. The base price is based on certain annual weighted average quality specifications, subject to suspension and rejection limits.

     In March 2005, NRG Energy entered into an agreement to purchase 23.75 million tons of coal over a period of four years and nine months from Buckskin Mining Company (Buckskin). The coal will be sourced from Buckskin’s mine in the Powder River Basin, Wyoming, and will be used primarily in NRG Energy’s coal-burning generation plants in the South Central region.

   Coal Transportation Agreement

     Louisiana Generating’s previous coal transportation agreement with DTE Energy expired March 31, 2005. Total payments under this agreement in 2005 are expected to be $1.5 million. The Company has entered into a new coal transportation agreement with Burlington Northern and Santa Fe Railway and an affiliate of ACT for a term of ten years, from April 1, 2005 through March 31, 2015. 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. A related agreement between Louisiana Generating and ACT grants Louisiana Generating the option to require ACT to perform the harbor operations related to the unloading of coal at Big Cajun II. Louisiana Generating has given notice to ACT that it will exercise the option and the transition of harbor services operations to ACT is scheduled for April 1, 2005.

   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 and one interconnection and operating agreement with Entergy Gulf States, Inc. on August 26, 2004. The Cajun facilities are connected to the transmission system of Entergy Gulf States, Inc. and power is delivered to the distribution cooperative at various delivery points on the transmission systems of Entergy Gulf States, Inc., Entergy Louisiana Inc., 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.

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NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

   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 pollutants released at its facilities or at off-site locations where it may have sent wastes, even if the release or off-site disposal was conducted in compliance with the law.

     The Company and its subsidiaries strive to at least meet 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, future laws and regulations are expected to require the addition of emission control equipment or the imposition of restrictions on the Company’s operations.

     The Company establishes accruals where it is probable that it will incur environmental costs under applicable law or contracts and it is possible to reasonably estimate these costs. The Company adjusts the accruals when new remediation or other environmental liability responsibilities are discovered and probable costs become estimable, or when current liability estimates are adjusted to reflect new information or a change in the law.

     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. We may also 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 hazardous material 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. The value of the trust fund is approximately $5.0 million at December 31, 2004, and the Company is making annual payments to the fund in the amount of about $116,000. See Note 17.

     The Louisiana Department of Environmental Quality, or LADEQ, has promulgated State Implementation Plan revisions to bring the Baton Rouge ozone nonattainment area into compliance with applicable 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 constitute a change-in-law covered by agreement between the Company and the electric cooperatives (power offtakers) 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.

   Legal Issues

U.S. Environmental Protection Agency Request for Information under Section 114 of the Clean Air Act and Notice of Violation

     On January 27, 2004, Louisiana Generating, LLC and Big Cajun II received a request for information under Section 114 of the federal Clean Air Act from the USEPA Region 6 seeking information primarily relating to physical changes made at Big Cajun II. Louisiana Generating, LLC and Big Cajun II submitted several responses to the USEPA in response to follow-up requests. On February 15, 2005, Louisiana Generating, LLC received a Notice of Violation, or NOV, alleging violations of the New Source Review provisions of the Clean Air Act at Big Cajun 2 Units 1 and 2 from 1998 through the NOV date. On April 7, 2005, we met with USEPA and the Department of Justice to discuss the NOV. Given the preliminary stage of this NOV process, the Company cannot predict the outcome of the matter at this time, but it is actively engaged with USEPA to address the issues.

27

NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

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, or DEQ, issued a Part 70 Air Permit modification to the Company 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 of Best Available Control Technology, or BACT. The BACT limitation for NOx 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 on September 8, 2002. DEQ alleged violations related to NOx emissions. The Company denied those allegations and will contest any future penalty assessment, while also seeking an amendment of its limit for NOx. Quarterly status reports are being submitted to an Administrative Law Judge. In late February 2004, the Company timely submitted to the DEQ an amended BACT analysis and an amended Prevention of Significant Deterioration and Title V permit application to amend the NOx limit, which application is pending. The Company may also assert breach of warranty claims against the manufacturer.

Travis Ballou, et. al. v. Ralph Mabey, et. al., No. 03-30343 in the United States Court of Appeals for the Fifth Circuit
Kenneth Austin, et.al v. Ralph Mabey, et. al., No. 00-728-D-1 in the United States District Court for the Middle District of Louisiana

     Two lawsuits against the Company 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, which included four plaintiffs, was dismissed on summary judgment. The District Court’s summary judgment ruling was affirmed by the U.S. Court of Appeals for the Fifth Circuit on February 10, 2005. On May 9, 2005, the District Judge granted six additional motions for summary judgment. In the remaining lawsuit involving 35 plaintiffs, the District Court has granted the Company’s Motions for Summary Judgment pertaining to nineteen plaintiffs, denied the Company’s Motions for Summary Judgment pertaining to four plaintiffs and is still considering the Company’s Motions for Summary Judgment pertaining to the remaining twelve plaintiffs.

BNSF Railway Company v. Louisiana Generating LLC, Case No. 531992, 19^th Judicial District Court, Parish of East Baton Rouge (filed May 6, 2005)

This lawsuit alleges breach of the coal transportation contract that expired on March 31, 2005. Specifically, the plaintiff alleges the shipment of coal via another carrier in 2004 and the failure to tender a minimum amount of coal during 2003, and further alleges that both actions constituted a breach of the contract. An accrual has been established.

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

     Pursuant to the requirements of Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies,” and related guidance, the Company records reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss is reasonably estimable. Management has assessed each of these matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought and the probability of success. Management’s judgment may, as a result of facts arising prior to resolution of these matters or other factors, prove inaccurate and investors should be aware that such judgment is made subject to the known uncertainty of litigation.

15. Regulatory Issues

     The Company’s assets are located within the franchise territory of Entergy Corporation, or Entergy, a vertically integrated utility. The utility performs the scheduling, reserve and reliability functions that are administered by the Independent System Operators, or ISOs, or Regional Transmission Organizations, or RTOs, in certain other regions of the United States. The Company operates a National Electric Reliability Council, or NERC, certified control areas within the Entergy franchise territory, which is comprised of most 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.

28

NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

Transacting counter-parties are required to reserve and purchase transmission services from the intervening transmission owners at their Federal Energy Regulatory Commission, or 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.

     On March 31, 2004, Entergy filed with FERC a proposal to have an independent coordinator of transmission, or ICT, monitor Entergy’s operation of its transmission system, to review the pricing structure for transmission expansion and to oversee a proposed weekly procurement process by which Entergy and other load serving entities could purchase energy. On March 22, 2005, FERC approved the ICT proposal for a two year period, subject to certain conditions. On May 27, 2005 Entergy filed its detailed ICT proposal with FERC. On December 17, 2004, FERC ordered that an investigation and evidentiary hearing be held on the issue of whether Entergy is providing access to its transmission system in a just and reasonable manner. On March 22, 2005, FERC suspended the hearing.

16. 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, Inc. 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, 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. All variable costs are incurred 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, 2004 and 2003 was $182.8 million and $183.2 million, respectively, and the corresponding accumulated depreciation and amortization was $11.5 million and $0.5 million, respectively, at December 31, 2004 and 2003.

17. 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 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. The Company’s predecessor deposited $1.1 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. At December 31, 2004 and 2003, the carrying value of the trust fund investments was approximately $5.0 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 the Company’s calculation of the asset retirement obligation discussed in Note 7.

18. Sale of Equity Method Investment

     In September 2002, NRG Energy agreed to sell its indirect 50% interest in SRW Cogeneration LP, or 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 of 2002 to write down the carrying value of its investment due to the pending sale. The sale closed on November 5, 2002.

19. Guarantees

     In November 2002, the FASB issued FASB Interpretation No. 45, or FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”. In connection with the adoption of Fresh Start, all outstanding guarantees were considered new; accordingly, the Company applied the provisions of FIN 45 to all of the guarantees.

29

NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

     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, 2004 and 2003, the Company’s obligations pursuant to its guarantees of the performance of its subsidiaries totaled approximately $0 and $13 million, respectively. In addition, the Company had one guarantee related to the purchase of transmission service that has an indeterminate value at December 31, 2004 and 2003.

     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, 2004 and 2003, $236.4 million and $239.3 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, 2004 and 2003, Bayou Cove had an intercompany note payable outstanding in the amount of $78.1 million and $81.7 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 $236.4 million and $239.3 million at December 31, 2004 and 2003, respectively.

     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 certain of NRG Energy’s current and future restricted subsidiaries (other than certain excluded project subsidiaries, foreign subsidiaries and certain other 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.

     On December 24, 2004, NRG Energy’s credit facility was amended and restated, or the Amended Credit Facility, whereby NRG Energy repaid outstanding amounts and issued a $450.0 million, seven-year senior secured term loan facility, a $350.0 million funded letter of credit facility, and a three-year revolving credit facility in an amount up to $150.0 million. The Amended 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 NRG Energy and certain of NRG’s current and future subsidiaries, including the following direct and indirect wholly owned subsidiaries:

Subsidiary

NRG South Central LLC (Direct)
Louisiana Generating LLC (Indirect)
NRG New Roads Holding LLC (Indirect)
NRG Sterlington Power LLC (Indirect)
Big Cajun I Peaking Power LLC (Indirect)
NRG Bayou Cove LLC (Indirect)

     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	$	1,725,000	Obligations under credit agreement		2013	Nonperformance
NRG Energy Amended and Restated Credit Agreement	$	800,000	Obligations under credit agreement		2011	Nonperformance

     On February 4, 2005, NRG Energy redeemed and retired $375.0 million of Second Priority Notes. As a result of the retirement, the joint and several payment and performance guarantee obligation of the Company and the above listed subsidiaries was reduced from $1,725.0 million to $1,350.0 million.

30

NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

20. Income Taxes

     The Company is included in the consolidated income 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 income tax provisions, as of the earliest period presented, as if the Company had prepared separate filings. The Company’s parent, NRG Energy, does not have a tax allocation agreement with its subsidiaries. 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 provision (benefit) for income taxes consists of the following:

	Reorganized Company						Predecessor Company
				For the			For the
				Period from			Period from
	For the Year			December 6,			January 1,			For the Year
	Ended			2003 to			2003 to			Ended
	December 31,			December 31,			December 5,			December 31,
	2004			2003			2003			2002
	(In thousands of dollars)
Current
Federal	$	—		$	—		$	—		$	—
State		—			—			—			—
		—			—			—			—
Deferred
Federal		16,157			161			—			(31,871	)
State		4,014			40			—			(7,918	)
		20,171			201			—			(39,789	)
Total income tax expense (benefit)	$	20,171		$	201		$	—		$	(39,789	)
Effective tax rate		40.9	%		40.7	%		0.0	%		23.1	%

     The pre-tax income (loss) was as follows:

	Reorganized Company				Predecessor Company
			For the		For the
			Period from		Period from
	For the Year		December 6,		January 1,			For the Year
	Ended		2003 to		2003 to			Ended
	December 31,		December 31,		December 5,			December 31,
	2004		2003		2003			2002
	(In thousands of dollars)
U.S.	$	49,350	$	494	$	(27,969	)	$	(171,874	)

     The components of the net deferred income tax asset were:

	Reorganized Company
	December 31,		December 31,
	2004		2003
	(In thousands of dollars)
Deferred tax liabilities
Property	$	41,308	$	—
Discount/premium on notes		8,631		9,648
Emissions credits		30,166		37,866
Other		113		129
Total deferred tax liabilities		80,218		47,643
Deferred tax assets

31

NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

	Reorganized Company
	December 31,			December 31,
	2004			2003
	(In thousands of dollars)
Deferred compensation, accrued vacation and other reserves		572			3,371
Difference between book and tax basis of contracts		125,820			129,960
Property		—			51,744
Domestic tax loss carryforwards		159,878			91,364
Other		11,341			8,768
Total deferred tax assets (before valuation allowance)		297,611			285,207
Valuation allowance		(217,393	)		(237,564	)
Net deferred tax assets		80,218			47,643
Net deferred tax asset	$	—		$	—

     The net deferred tax asset consists of:

	Reorganized Company
	December 31,		December 31,
	2004		2003
	(In thousands of dollars)
Net current deferred tax asset	$	—	$	—
Net noncurrent deferred tax asset	$	—	$	—
Net deferred tax asset	$	—	$	—

     Management believes that it is more likely than not that no benefit will be realized on a substantial portion of the Company’s deferred tax assets. This assessment included consideration of positive and negative evidence, including the Company’s current financial position and results of current operations, projected future taxable income, including projected operating and capital gains and our available tax planning strategies. Therefore, a valuation allowance of $217.4 million was recorded against the net deferred tax assets, including net operating loss carryforwards.

     In connection with the Company’s emergence from bankruptcy, the 2003 net operating loss carryforward was effectively increased as a result of the Company’s election in 2004 to reduce the tax basis of property on a going forward basis. This election was made in 2004 in connection with tax planning strategies for future periods and accordingly was recorded subsequent to the period ended December 31, 2003.

     Subsequently recognized tax benefits relating to the valuation allowance for deferred tax assets as of December 31, 2004, will be allocated to intangible assets.

     In 2004, the Company utilized $69.7 million of U.S. net operating losses carryforward of $467.4 million which will expire by 2023 if unutilized. There is a net carryforward amount of $397.7 million available at year end 2004.

     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
	For the Year				December 6,				January 1,					For the Year
	Ended				2003 to				2003 to					Ended
	December 31,				December 31,				December 5,					December 31,
	2004				2003				2003					2002
	(In thousands of dollars)
Income (loss) before taxes	$	49,350			$	494			$	(27,969	)			$	(171,874	)
Tax at 35%		17,273	35.0	%		173	35.0	%		(9,789	)	35.0	%		(60,156	)	35.0	%
State taxes (net of federal benefit)		2,568	5.2	%		26	5.3	%		(1,455	)	5.2	%		(5,147	)	3.0	%
Valuation allowance		318	0.7	%		—	0.0	%		11,244		(40.2	)%		35,699		(20.8	)%
Other		12	0.0	%		2	0.4	%		—		—	%		(10,185	)	5.9	%
Income tax expense (benefit)	$	20,171	40.9	%	$	201	40.7	%	$	—		0.0	%	$	(39,789	)	23.1	%

     There is a net carryforward amount of $397.7 million available at year end 2004 which will expire by 2023 if unutilized.

32

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
ON FINANCIAL STATEMENT SCHEDULE

To the Member of
NRG South Central Generating LLC:

     Our audits of the consolidated financial statements referred to in our reports dated March 10, 2004, also included an audit of the financial statement schedule listed herein. In our opinion, this financial statement schedule for the periods from December 6, 2003 to December 31, 2003 and from January 1, 2003 to December 5, 2003, and for the year 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

33

NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES

SCHEDULE II. VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2004, 2003 and 2002

			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:
Reorganized Company
Year Ended December 31, 2004	$	237,564	$	—	$	—		$	(20,171	)	$	217,393
December 6 - December 31, 2003		237,765		—		—			(201	)		237,564
Predecessor Company
January 1 – December 5, 2003		35,699		11,244		190,822	*		—			237,765
Year Ended December 31, 2002		—		35,699		—			—			35,699

* December 6, 2003 — Fresh Start Balance

34

EX-99.3

EXHIBIT 99.3

LOUISIANA GENERATING LLC

FINANCIAL STATEMENTS

At December 31, 2004 and 2003,
and for the Year Ended December 31, 2004,
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

1

LOUISIANA GENERATING LLC

INDEX

	Page
Reports of Independent Registered Public Accounting Firms		3
Balance Sheets at December 31, 2004 and 2003		6
Statements of Operations for the year ended December 31, 2004, 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		7
Statements of Member’s Equity for the year ended December 31, 2004, 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		8
Statements of Cash Flows for the year ended December 31, 2004, 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		9
Notes to Financial Statements		10
Report of Independent Registered Public Accounting Firm on Financial Statement Schedule		30
Financial Statement Schedule		31

2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Member of
Louisiana Generating LLC

     We have audited the accompanying balance sheet of Louisiana Generating LLC as of December 31, 2004, and the related statements of operations, member’s equity, and cash flows for the year then ended. In connection with our audit of the financial statements, we have also audited the financial statement schedule “Schedule II Valuation and Qualifying Accounts.” These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audit.

     We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

     In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Louisiana Generating LLC as of December 31, 2004, and the results of its operations and its cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/S/	KPMG LLP
	KPMG LLP

Philadelphia, Pennsylvania
May 27, 2005

3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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 (Reorganized Company) at December 31, 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 audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 audit provides a reasonable basis for our opinion.

     As discussed in Notes 1 and 2 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

4

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Member of
Louisiana Generating LLC

     In our opinion, the accompanying statements of operations, of member’s equity, and of cash flows present fairly, in all material respects, the results of operations and cash flows of Louisiana Generating LLC (Predecessor Company) for the period from January 1, 2003 to December 5, 2003 and for the year 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). 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 Notes 1 and 2 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

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LOUISIANA GENERATING LLC

BALANCE SHEETS

	December 31,		December 31,
	2004		2003
	(In thousands of dollars)
ASSETS
Current assets
Cash and cash equivalents	$	19,861	$	4,612
Restricted cash		—		99
Accounts receivable		40,231		37,039
Accounts receivable — affiliates		—		3,812
Note receivable		—		584
Inventory		32,819		34,077
Prepayments and other current assets		7,130		6,588
Total current assets		100,041		86,811
Property, plant and equipment, net of accumulated depreciation of $61,933 and $2,452, respectively		834,057		863,096
Intangible assets, net of accumulated amortization of $13,752, and $787, respectively		77,581		120,854
Decommissioning fund investments		4,954		4,809
Other assets held for sale		871		685
Total assets	$	1,017,504	$	1,076,255
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	5,835	$	10,430
Accounts payable — affiliates		15,697		—
Other current liabilities		17,984		18,433
Total current liabilities		39,516		28,863
Out of market power contracts		351,649		387,524
Other long-term obligations		3,282		9,789
Total liabilities		394,447		426,176
Commitments and contingencies
Member’s equity		623,057		650,079
Total liabilities and member’s equity	$	1,017,504	$	1,076,255

The accompanying notes are an integral part of these financial statements.

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LOUISIANA GENERATING LLC

STATEMENTS OF OPERATIONS

	Reorganized Company					Predecessor Company
			For the			For the
			Period from			Period from
	For the Year		December 6,			January 1,			For the Year
	Ended		2003 to			2003 to			Ended
	December 31,		December 31,			December 5,			December 31,
	2004		2003			2003			2002
	(In thousands of dollars)
Revenues	$	432,028	$	27,886		$	355,984		$	399,458
Operating costs		292,556		19,351			254,124			281,190
Depreciation and amortization		59,579		2,452			28,916			29,671
General and administrative expenses		20,942		1,868			8,997			5,284
Reorganization items		1,093		104			20,241			—
Impairment charges		493		—			—			—
Restructuring charges		—		—			—			208
Income from operations		57,365		4,111			43,706			83,105
Other income (expense), net		604		99			336			779
Interest income (expense)		1,282		(3,442	)		(66,067	)		(71,220	)
Income (loss) before income taxes		59,251		768			(22,025	)		12,664
Income tax expense (benefit)		23,833		312			(8,776	)		8,687
Net income (loss)	$	35,418	$	456		$	(13,249	)	$	3,977

The accompanying notes are an integral part of these financial statements.

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LOUISIANA GENERATING LLC

STATEMENTS OF MEMBER’S EQUITY

					Member			Accumulated			Total
	Member				Contributions/			Net Income			Member’s
	Units		Amount		Distributions			(Loss)			Equity
	(In thousands of dollars)
Balances at December 31, 2001 (Predecessor Company)		1,000	$	1	$	192,276		$	26,864		$	219,141
Net income		—		—		—			3,977			3,977
Contribution from member		—		—		47,594			—			47,594
Balances at December 31, 2002 (Predecessor Company)		1,000		1		239,870			30,841			270,712
Net 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		—		—		—			456			456
Balances at December 31, 2003 (Reorganized Company)		1,000	$	1	$	649,622		$	456		$	650,079
Net income		—		—		—			35,418			35,418
Distribution to member		—		—		(26,566	)		(35,874	)		(62,440	)
Balances at December 31, 2004 (Reorganized Company)		1,000	$	1	$	623,056		$	—		$	623,057

The accompanying notes are an integral part of these financial statements.

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LOUISIANA GENERATING LLC

STATEMENTS OF CASH FLOWS

	Reorganized Company						Predecessor Company
				For the			For the
				Period from			Period from
	For the Year			December 6,			January 1,			For the Year
	Ended			2003 to			2003 to			Ended
	December 31,			December 31,			December 5,			December 31,
	2004			2003			2003			2002
	(In thousands of dollars)
Cash flows from operating activities
Net income (loss)	$	35,418		$	456		$	(13,249	)	$	3,977
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation and amortization		59,579			2,452			28,916			29,671
Deferred income taxes		23,833			312			(8,776	)		8,687
Restructuring and impairment charges		493			—			9,141			50
Amortization of intangibles		12,965			—			—			—
Amortization of debt issuance costs		—			—			399			441
Amortization of out-of-market power contracts		(35,875	)		(2,199	)		—			—
Loss on disposal of equipment		271			—			—			—
Changes in assets and liabilities
Accounts receivable		(3,192	)		673			8,788			(2,736	)
Inventory		1,258			5,325			16,689			(11,408	)
Prepayments and other current assets		(542	)		1,413			(5,074	)		(559	)
Accounts payable		(4,595	)		(4,113	)		983			(12,869	)
Accounts payable and receivable — affiliates, net		19,509			2,857			(66,227	)		76,360
Accrued interest — affiliates		—			(15,296	)		(40,117	)		34,960
Other current liabilities		(449	)		(14,216	)		14,123			1,505
Other assets and liabilities		(363	)		(164	)		7,752			344
Net cash provided by (used in) operating activities		108,310			(22,500	)		(46,652	)		128,423
Cash flows from investing activities
Capital expenditures		(31,304	)		(329	)		(8,057	)		(12,231	)
Decrease (increase) in note receivable		584			916			1,500			(3,000	)
Increase in trust funds		—			—			(192	)		—
Decrease (increase) in restricted cash		99			133,694			(24,457	)		(109,336	)
Net cash (used in) provided by investing activities		(30,621	)		134,281			(31,206	)		(124,567	)
Cash flows from financing activities
Contributions by member		—			632,440			88,999			47,594
Net proceeds/payments on revolver		—			—			—			(40,000	)
Payment of note payable — affiliate		—			(750,750	)		—			(12,750	)
Checks in excess of cash		—			—			—			(1,908	)
Distribution to member		(62,440	)		—			—			—
Net cash (used in) provided by financing activities		(62,440	)		(118,310	)		88,999			(7,064	)
Net change in cash and cash equivalents		15,249			(6,529	)		11,141			(3,208	)
Cash and cash equivalents
Beginning of period		4,612			11,141			—			3,208
End of period	$	19,861		$	4,612		$	11,141		$	—
Supplemental disclosures of cash flow information
Cash paid for interest	$	—		$	29,999		$	105,785		$	36,260

The accompanying notes are an integral part of these financial statements.

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LOUISIANA GENERATING LLC

NOTES TO FINANCIAL STATEMENTS

1. Organization

     Louisiana Generating LLC, or Louisiana Generating or the Company, is an indirect wholly owned subsidiary of NRG Energy, Inc., or NRG Energy. NRG South Central LLC, or South Central, owns 100% of the Company.

     The Company was formed for the purpose of acquiring, owning, operating and maintaining the electric generating facilities acquired from Cajun Electric Power Cooperative, Inc., or Cajun Electric. Pursuant to a competitive bidding process, as part of the Chapter 11 bankruptcy proceeding of Cajun Electric, Louisiana Generating acquired the non-nuclear electric power generating assets of Cajun Electric.

     From May 14, 2003 to December 23, 2003, NRG Energy and a number of its subsidiaries, including the Company, undertook a comprehensive reorganization and restructuring under chapter 11 of the United States Bankruptcy Code. The Northeast/South Central Plan of Reorganization, relating to the Company, the NRG Northeast Generating LLC subsidiaries and the other South Central subsidiaries, 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.

     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 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 holder.

2. Summary of Significant Accounting Policies

   Basis of Presentation

     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 Statement of Position 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code”, or SOP 90-7.

     For financial reporting purposes, close of business on December 5, 2003, represents the date of the Company’s emergence from bankruptcy because that is the date of emergence for the ultimate parent company, NRG Energy. As previously stated, the Company emerged from bankruptcy on December 23, 2003. The accompanying financial statements reflect the impact of the Company’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, pre-emergence from bankruptcy
	The Company’s operations prior to December 6, 2003
“Reorganized Company”	The Company, post-emergence from bankruptcy
	The Company’s operations, December 6, 2003 - December 31, 2004

   NRG Energy Fresh Start Reporting/Push Down Accounting

     In accordance with SOP 90-7, 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 immediately before confirmation receive less than 50 percent of the voting shares of the emerging entity. NRG Energy met these requirements and adopted Fresh Start reporting resulting in the creation of a new reporting entity designated as Reorganized NRG. 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.

     The bankruptcy court issued a confirmation order approving 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. The Xcel Energy settlement agreement was entered into on December 5, 2003. NRG Energy 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.

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LOUISIANA GENERATING LLC

     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, or SFAS No. 109, “Accounting for Income Taxes”. The net effect of all Fresh Start adjustments resulted in a gain of $3.9 billion (comprised of a $4.1 billion gain from continuing operations and a $0.2 billion loss from discontinued operations), 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 and push down accounting 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 NRG Energy’s 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 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. 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.

     A separate plan of reorganization was filed for South Central 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, NRG Energy accounted for these entities as if they had emerged from bankruptcy at the same time that NRG Energy emerged, as it is believed that NRG Energy continued to maintain control over the South Central facilities throughout the bankruptcy process.

     Due to the adoption of Fresh Start upon NRG Energy’s emergence from bankruptcy and the impact of push down accounting, the Reorganized Company’s 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.

   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 to satisfy the requirements of certain debt agreements and funds held within the Company’s projects that are restricted in their use. These funds are used to pay for current operating expenses and current debt service payments, per the restrictions of the debt agreements.

   Inventory

     Inventory consists principally of coal, spare parts and fuel oil and is valued at the lower of weighted average cost or market.

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LOUISIANA GENERATING LLC

   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, the Company 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 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.

Facilities and equipment 1 to 35 years

   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.

   Intangible Assets

     Intangible assets represent contractual rights held by the Company. Intangible assets are amortized over their economic useful life and reviewed for impairment whenever events or changes in circumstances indicate carrying values may not be recoverable.

     Intangible assets consist primarily of the fair value of power sales agreements and emission allowances. The amounts related to the power sales agreements are amortized as a reduction to revenue over the terms and conditions of each contract. Emission allowance related amounts are amortized as additional fuel expense based upon the actual level of emissions from the respective plant through 2023.

   Out of Market Power Contracts

     As part of Fresh Start, the Company recognized liabilities for executory contracts, or power sales agreements, related to the sale of electric capacity and energy in future periods, where the fair value was determined to be significantly out of market as compared to market expectations. These liabilities represent the out-of-market portion of the executory contracts determined as of the Fresh Start date. 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 are delivered. Where bilateral markets exist and the Company physically delivers electricity from its plants, we record revenue on a gross basis. 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 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 purchases, sales and hedging transactions to manage the Company’s electricity price exposure. See Note 11 – Related Party Transactions.

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LOUISIANA GENERATING LLC

   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 18 — 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 the members 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.

   Credit Risk

     Credit risk relates to the risk of loss resulting from non-performance or non-payment by counter-parties pursuant to the terms of their contractual obligations. NRG Energy monitors and manages the credit risk of its affiliates, including the Company, through credit policies which include an (i) established credit approval process, (ii) daily monitoring of counter-party credit limits, (iii) the use of credit mitigation measures such as margin, collateral, credit derivatives or prepayment arrangements, (iv) the use of payment netting agreements and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counter-party. Risk surrounding counter-party performance and credit could ultimately impact the amount and timing of expected cash flows. NRG Energy has credit protection within various agreements to call on additional collateral support if necessary.

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

   Fair Value of Financial Instruments

     The carrying amounts of cash and cash equivalents, restricted cash, receivables, accounts payables, and accrued liabilities approximate fair value because of the short maturity of these instruments.

   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, disclosure of contingent 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.

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LOUISIANA GENERATING LLC

   Recent Accounting Pronouncements

     In November 2004, the FASB issued SFAS No. 151, “Inventory Costs- an amendment of ARB No. 43, Chapter 4”. This statement amends the guidance in ARB No.43, Chapter 4, “Inventory Pricing”, and requires that idle facility expense, excessive spoilage, double freight, and rehandling costs be recognized as current-period charges regardless of whether they meet the criterion of “so abnormal” established by Accounting Research Bulletin No. 43. SFAS No.151 is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The Company is currently in the process of evaluating the potential impact that the adoption of this statement will have on the Company’s financial position and results of operations.

     In December 2004, the FASB issued two FASB Staff Positions, or FSPs, regarding the accounting implications of the American Jobs Creation Act of 2004 related to (1) the deduction for qualified domestic production activities (FSP FAS 109-1) and (2) the one-time tax benefit for the repatriation of foreign earnings (FSP FAS 109-2). In FSP FAS 109-1, “Application of FASB Statement No. 109, “Accounting for Income Taxes,” to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004”, the Board decided that the deduction for qualified domestic production activities should be accounted for as a special deduction under FASB Statement No. 109, “Accounting for Income Taxes” and rejected an alternative view to treat it as a rate reduction. Accordingly, any benefit from the deduction should be reported in the period in which the deduction is claimed on the tax return. FSP FAS 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004”, addresses the appropriate point at which a company should reflect in its financial statements the effects of the one-time tax benefit on the repatriation of foreign earnings. Because of the proximity of the Act’s enactment date to many companies’ year-ends, its temporary nature, and the fact that numerous provisions of the Act are sufficiently complex and ambiguous, the Board decided that absent additional clarifying regulations, companies may not be in a position to assess the impact of the Act on their plans for repatriation or reinvestment of foreign earnings. Therefore, the Board provided companies with a practical exception to FAS 109’s requirements by providing them additional time to determine the amount of earnings, if any, that they intend to repatriate under the Act’s beneficial provisions. The Board confirmed, however, that upon deciding that some amount of earnings will be repatriated, a company must record in that period the associated tax liability, thereby making it clear that a company cannot avoid recognizing a tax liability when it has decided that some portion of its foreign earnings will be repatriated. The Company is currently in the process of evaluating the potential impact that the adoption of FSP FAS 109-1 will have on our consolidated financial position and results of operations. The Company does not believe that the potential adoption of FSP 109-2 will have a material impact on our consolidated financial position and results of operation.

     In March 2005, the Financial Accounting Standards Board (FASB) issued Interpretation No. 47 (FIN 47) to Financial Accounting Standard No. 143 (SFAS No. 143) governing the application of Asset Retirement Obligations. FIN 47 clarifies that the term “conditional asset retirement obligation” as used in SFAS 143. SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional but there may remain some uncertainty as to the timing and/or method of settlement. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred — generally upon acquisition, construction, or development and/or through the normal operation of the asset. SFAS No. 143 acknowledges that in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation. FIN 47 clarifies when the company would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective for fiscal years ending after December 15, 2005 and we are currently evaluating the impact of this guidance.

3. Emergence from Bankruptcy and Fresh Start Reporting

     In accordance with the requirements of SFAS No. 141 “Business Combinations”, and push down accounting, the Company’s fair value of $17.2 million as of the Fresh Start date 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 Fresh Start as of December 5, 2003, the Reorganized Company’s statement 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 Fresh Start.

     The effects of the push down accounting adjustments on the Company’s condensed 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)
Current Assets	$	245,228	$	(7,010	)	$	238,218
Non-current Assets		946,040		46,292			992,332
Total Assets	$	1,191,268	$	39,282		$	1,230,550
Current Liabilities	$	809,862	$	3,376		$	813,238
Non-current Liabilities		34,944		365,185			400,129
		844,806		368,561			1,213,367
Members’ Equity		346,462		(329,279	)		17,183
Total Liabilities and Member’s Equity	$	1,191,268	$	39,282		$	1,230,550

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LOUISIANA GENERATING LLC

4. Other Charges

     Reorganization items, impairment charges and restructuring charges included in the statements of operations include the following:

	Reorganized Company				Predecessor Company
			For the		For the
			Period from		Period from
	For the Year		December 6,		January 1,		For the Year
	Ended		2003 to		2003 to		Ended
	December 31,		December 31,		December 5,		December 31,
	2004		2003		2003		2002
	(In thousands of dollars)
Reorganization items	$	1,093	$	104	$	20,241	$	—
Impairment charges		493		—		—		—
Restructuring charges		—		—		—		208
	$	1,586	$	104	$	20,241	$	208

   Reorganization Items

     For the year ended December 31, 2004, the Company recorded $1.1 million of reorganization charges. For the period from January 1, 2003 to December 5, 2003, 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 refinancing transaction completed in December 2003. Both items were expensed in November 2003, as they were determined to be an allowed claim at that time. The following table provides the detail of the types of costs incurred. There were no reorganization items in 2002.

					Predecessor
	Reorganized Company				Company
			For the		For the
			Period from		Period from
	For the Year		December 6,		January 1,
	Ended		2003 to		2003 to
	December 31,		December 31,		December 5,
	2004		2003		2003
	(In thousands of dollars)
Reorganization items
Settlement of pre-petition claims	$	962	$	—	$	—
Legal and advisor fees related to bankruptcy		131		104		615
Deferred financing costs		—		—		9,141
Pre-payment charge		—		—		11,261
Interest earned on accumulated cash		—		—		(776	)
Total reorganization items	$	1,093	$	104	$	20,241

   Impairment Charges

     In January 2004, the Company closed the South Central regional office in Baton Rouge, Louisiana and offered it for sale. During the fourth quarter of 2004, the Company recorded a charge of $0.5 million related to the impairment in the net realizable value based on two offers received.

   Restructuring Charges

     In 2002, the Company incurred $0.2 million of severance costs associated with the combining of various functions and restructuring costs consisting of advisor fees.

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LOUISIANA GENERATING LLC

5. Inventory

     Inventory, which is valued at the lower of weighted average cost or market, consists of:

	Reorganized Company
	December 31,		December 31,
	2004		2003
	(In thousands of dollars)
Coal	$	24,987	$	26,108
Spare parts		6,897		7,186
Fuel oil		935		783
Total inventory	$	32,819	$	34,077

6. Property, Plant and Equipment

     The major classes of property, plant and equipment were as follows:

	Average
	Remaining	Reorganized Company
	Useful	December 31,			December 31,			Depreciable
	Life	2004			2003			Lives
	(In thousands of dollars)
Land		$	20,142		$	20,142
Facilities, machinery and equipment	17 years		873,705			845,077		1-35 years
Construction in progress			2,143			329
Accumulated depreciation			(61,933	)		(2,452	)
Property, plant and equipment, net		$	834,057		$	863,096

7. Asset Retirement Obligations

     Effective January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations”, or 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 ash disposal site closures. 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.

     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, the period from December 6, 2003 to December 31, 2003 and the year ended December 31, 2004. The asset retirement obligations are included in other long-term obligations in the balance sheets. As a result of applying push down accounting, the Company revalued the asset retirement obligations on December 6, 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 fresh start reporting on December 6, 2003, equal to 500 to 600 basis points.

			Reorganized Company
			Accretion for
			Period				Accretion for
	Beginning		December 6,		Ending		the Year		Ending
	Balance		to		Balance		Ended		Balance
	December 6,		December 31,		December 31,		December 31,		December 31,
	2003		2003		2003		2004		2004
	(In thousands of dollars)
Asset retirement obligations	$	2,051	$	12	$	2,063	$	144	$	2,207

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LOUISIANA GENERATING LLC

	Predecessor Company
	Beginning		Accretion for		Adjustment		Ending
	Balance		Period Ended		For Fresh		Balance
	January 1,		December 5,		Start		December 5,
	2003		2003		Reporting		2003
	(In thousands of dollars)
Asset retirement obligations	$	291	$	42	$	1,718	$	2,051

8. Intangible Assets

   Reorganized Company

     Upon adoption of Fresh Start and application of push down accounting, the Company established certain intangible assets for power sales agreements and plant emission allowances. These intangible assets are amortized over their respective lives based on a straight-line or units of production basis.

     Power sales agreements are amortized as a reduction to revenue over the terms and conditions of each contract. The remaining amortization period for the power sales agreements is three years. Emission allowances are amortized as additional fuel expense based upon the actual level of emissions from the respective plants through 2023. Aggregate amortization recognized for the year ended December 31, 2004 was approximately $13.0 million. Amortization expense recognized during the period from December 6, 2003 to December 31, 2003 was $0.8 million related only to the power sales agreements. No emission allowances were used during this period. The annual aggregate amortization expense for each of the five succeeding years is expected to approximate $9.3 million in years one through three, and $4.4 million in years four and five for both the power sales agreements and emission allowances. The expected annual amortization of these amounts is expected to change as the Company relieves the tax valuation allowance as explained below.

     For the year ended December 31, 2004, the Company reduced its tax valuation allowance by $23.8 million, and in accordance with SOP 90-7, recorded a corresponding reduction related to the Company’s intangible assets. As a result of the recognition of a deferred tax asset valuation allowance in accordance with SOP 90-7, any future benefits from reducing the valuation allowance should first reduce intangible assets until exhausted, and thereafter be recorded as a direct addition to paid-in capital. Intangible assets were also decreased by $6.5 million related to a true-up of certain other tax evaluations.

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LOUISIANA GENERATING LLC

Intangible assets Consisted of the following:

	Power Sale			Emission
	Agreements			Allowances			Total
	(In thousands of dollars)
Balances as of December 6, 2003	$	27,800		$	93,841		$	121,641
Amortization		(787	)		—			(787	)
Balances as of December 31, 2003		27,013			93,841			120,854
Tax valuation adjustment		(5,327	)		(18,506	)		(23,833	)
Amortization		(7,972	)		(4,993	)		(12,965	)
Other adjustments		(1,447	)		(5,028	)		(6,475	)
Balances as of December 31, 2004	$	12,267		$	65,314		$	77,581

Predecessor Company

     The Company had intangible assets that were amortized and consisted of service contracts. For the period January 1, 2003 to December 5, 2003 and for the year ended December 31, 2002, the Company recorded approximately $0 and $123,000 of amortization expense, respectively.

9. Accounting for Derivative Instruments and Hedging Activity

     SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” as amended by SFAS No. 137, SFAS No. 138 and SFAS No. 149 requires the Company to recognize all derivative instruments on the balance sheet as either assets or liabilities and measure them at fair value each reporting period. If certain conditions are met, the Company may be able to designate derivatives as cash flow hedges and defer the effective portion of the change in fair value of the derivatives in Accumulated Other Comprehensive Income (OCI) and subsequently recognize in earnings when the hedged items impact income. The ineffective portion of a cash flow hedge is immediately recognized in income.

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

     For derivatives that are neither designated as cash flow hedges or do not qualify for hedge accounting treatment, the changes in the fair value will be immediately recognized in earnings.

     The Company had no derivative contracts at December 31, 2004 and 2003 or during the year ended December 31, 2004, the period of December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 or the year ended December 31, 2002.

10. Financial Instruments

     The estimated fair values of the Company’s recorded financial instruments are as follows:

	Reorganized Company
	December 31, 2004				December 31, 2003
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
	(In thousands of dollars)
Cash	$	19,861	$	19,861	$	4,612	$	4,612
Restricted cash		—		—		99		99
Accounts receivable		40,231		40,231		37,039		37,039
Accounts receivable – affiliates		—		—		3,812		3,812
Note receivable		—		—		584		584
Decommissioning funds		4,954		4,954		4,809		4,809
Accounts payable		5,835		5,835		10,430		10,430
Accounts payable – affiliates		15,697		15,697		—		—

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LOUISIANA GENERATING LLC

     For cash and cash equivalents, restricted cash, accounts receivable and accounts payable, the carrying amount approximates fair value because of the short-term maturity of those instruments. The fair value of note receivable approximates carrying value as the underlying instruments bear a variable market interest rate. Decommissioning fund investments are comprised of various U.S. debt securities and are carried at amortized cost, which approximates their fair value.

11. Related Party Transactions

     The Company has an energy marketing services agreement with NRG Power Marketing Inc., or NRG Power Marketing, a wholly owned subsidiary of NRG Energy. The agreement is effective for consecutive one-year terms until terminated by either party upon 90 days written notice before the end of any such term. 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 costs, taxes, employee labor, contract services, etc.). The Company incurs no fees related to this energy marketing services agreements with NRG Power Marketing.

     The Company has an operation and maintenance agreement with NRG Operating Services, Inc., or 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. These costs are reflected in operating costs in the statement of operations.

     For the year ended December 31, 2004, 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, 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 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. For the year ended December 31, 2004, the amounts paid also included a proportionate share of NRG Energy’s corporate restructuring charges.

     For the year ended December 31, 2004, 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, the Company incurred approximately $9.8 million, $1.2 million, $3.2 million and $0.2 million, respectively, for corporate support and services. The amounts paid for the year ended December 31, 2004 reflect an overall increase in corporate level general and administrative expenses. Corporate general, administrative and development expenses increase in 2004 due to higher legal fees, increased audit costs and increased consulting costs due to NRG Energy’s Sarbanes-Oxley implementation. The method of allocating these costs remained the same from the prior years.

     At December 31, 2004, the Company had an accounts payable — affiliates balance of approximately $15.7 million and at December 31, 2003, the Company had an accounts receivable — affiliates balance of $3.8 million. These balances are settled on a periodic basis and are due to or from multiple entities which are wholly owned subsidiaries of NRG Energy Inc, the parent company of South Central Generating LLC. South Central Generating LLC is the parent company of Louisiana Generating LLC.

     During 2004, Louisiana Generating sold 50% of its interest in certain switchyard assets to its affiliate, Big Cajun I Peakers for a purchase price of $0.2 million. Louisiana Generating and its affiliate Big Cajun I Peakers share certain facilities and services at the Big Cajun I plant site and have entered into an Amended and Restated Shared Facilities Agreement to govern their respective responsibilities pertaining to such shared facilities and services. 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.

     For the year ended December 31, 2004, 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, the Company recorded revenue of $14.1 million, $1.2 million, $0 and $0, respectively, from amortization of out of market power contracts with subsidiaries of South Central Generating LLC.

     For the year ended December 31, 2004, 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, the Company recorded operating costs of $23.7 million, $2.0 million, $22.1 million, and $24.7 million, respectively, for power purchases from subsidiaries of South Central Generating LLC.

     In August 2004, NRG Energy entered into a contract to purchase 1,540 aluminum railcars from Johnston America Corporation to be used for the transportation of low sulfur coal from Wyoming to NRG Energy’s coal burning generating plants, including the Cajun Facilities. On February 18, 2005, NRG Energy entered into a ten-year operating lease agreement with GE Railcar Services

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LOUISIANA GENERATING LLC

Corporation, or GE, for the lease of 1,500 railcars and delivery commenced in February 2005. NRG Energy assigned certain of its rights and obligations for 1,500 railcars under the purchase agreement with Johnston America to GE. Accordingly, the railcars which NRG Energy leases from GE under the arrangement described above will be purchased by GE from Johnston America in lieu of NRG Energy’s purchase of those railcars.

12. Sales to Significant Customers

     The Company derives revenues from two significant customers:

	Reorganized Company						Predecessor Company
				For the			For the
				Period from			Period from
	For the Year			December 6,			January 1,			For the Year
	Ended			2003 to			2003 to			Ended
	December 31,			December 31,			December 5,			December 31,
	2004			2003			2003			2002
	(Percent of total revenues)
Sales to:
Southwest Louisiana Electric Membership Corporation		16.6	%		16.8	%		18.3	%		16.8	%
Dixie Electric Membership Corporation		16.2	%		16.6	%		17.5	%		15.9	%

     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 71.6%, 82.7%, 85.0%, and 80.2%, of the Company’s total revenues during the year ended December 31, 2004, 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.

13. Commitments and Contingencies

   Operating Lease Commitments

     The Company leases certain of its equipment under operating leases expiring on various dates through 2008. Rental expense under these operating leases was approximately $0.4 million for the year ended December 31, 2004, $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 for the year ended December 31, 2002. Future minimum lease payments under these leases for the years ending after December 31, 2004, are as follows:

	Total
	(In thousands of dollars)
2005	$	194.0
2006		130.3
2007		36.8
2008		0.4

   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 out of market were

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LOUISIANA GENERATING LLC

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 December 31, 2004 and December 31, 2003, was $351.6 million and $390.5 million, respectively. During the year ended December 31, 2004 and for the period from December 6, 2003 to December 31, 2003, approximately $35.9 million and $3.0 million, respectively 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, 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 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 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.

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LOUISIANA GENERATING LLC

     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 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.

     During contract year six, the Company will establish a rate fund equal to $18 million times the ratable share of Form B distribution cooperative’s aggregate 1998 demand to total 1998 demand. Based on the one existing Form B customer, the fund will be approximately $720,000; this amount may increase if additional cooperatives join the Form B cooperatives.

   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.

     The Company 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.

     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.

   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, or SWEPCO, one agreement with South Mississippi Electric Power Association, or SMEPA, and one agreement with Municipal Energy Agency of Mississippi, or 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.

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LOUISIANA GENERATING LLC

     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 was fixed through May 31, 2004, and increases for the period June 1, 2004 through 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 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 Agreements

     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. In December 2004, the Company extended the coal purchase contract through 2007. 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.

     In March 2005, NRG Energy entered into an agreement to purchase 23.75 million tons of coal over a period of four years and nine months from Buckskin Mining Company, or Buckskin. The coal will be sourced from Buckskin’s mine in the Powder River Basin, Wyoming, and will be used primarily in NRG Energy’s coal-burning generation plants in the South Central region.

   Coal Transportation Agreement

     The Company’s previous coal transportation agreement with DTE Energy expired March 31, 2005. Total payments under this agreement in 2005 are expected to be $1.5 million. The Company has entered into a new coal transportation agreement with Burlington Northern and Santa Fe Railway and affiliates of ACT for a term of ten years, from April 1, 2005 through March 31, 2015. 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. A related agreement between the Company and ACT grants the Company the option to require ACT to perform the harbor operations related to the unloading of coal at Big Cajun II. The Company has given notice to ACT that it will exercise the option and the transition of harbor services operations to ACT is scheduled for April 1, 2005.

   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 and one interconnection and operating agreement with Entergy Gulf States, Inc. on August 26, 2004. 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

23

LOUISIANA GENERATING LLC

environmental impacts. Also, the Company could be held responsible under environmental and safety laws for the cleanup of pollutants released at its facilities or at off-site locations where it may have sent wastes, even if the release or off-site disposal was conducted in compliance with the law.

     The Company and its subsidiaries strive to at least meet 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, future laws and regulations are expected to require the addition of emission control equipment or the imposition of restrictions on the Company’s operations.

     The Company establishes accruals where it is probable that it will incur environmental costs under applicable law or contracts and it is possible to reasonably estimate these costs. The Company adjusts the accruals when new remediation or other environmental liability responsibilities are discovered and probable costs become estimable, or when current liability estimates are adjusted to reflect new information or a change in the law.

     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. We may also 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 hazardous material 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. The value of the trust fund is approximately $5.0 million at December 31, 2004, and the Company is making annual payments to the fund in the amount of about $116,000. See Note 16.

     The Louisiana Department of Environmental Quality has promulgated State Implementation Plan revisions to bring the Baton Rouge ozone nonattainment area into compliance with applicable 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 constitute a change-in-law covered by agreement between the Company and the electric cooperatives (power offtakers) 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.

   Legal Issues

U.S. Environmental Protection Agency Request for Information under Section 114 of the Clean Air Act and Notice of Violation

     On January 27, 2004, Louisiana Generating, LLC and Big Cajun II received a request for information under Section 114 of the federal Clean Air Act from the USEPA Region 6 seeking information primarily relating to physical changes made at Big Cajun II. Louisiana Generating, LLC and Big Cajun II submitted several responses to the USEPA in response to follow-up requests. On February 15, 2005, Louisiana Generating, LLC received a Notice of Violation, or NOV, alleging violations of the New Source Review provisions of the Clean Air Act at Big Cajun II Units 1 and 2 from 1998 through the NOV date. On April 7, 2005, we met with USEPA and the Department of Justice to discuss the NOV. Given the preliminary stage of this NOV process, the Company cannot predict the outcome of the matter at this time, but it is actively engaged with USEPA to address the issues.

   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, or DEQ, issued a Part 70 Air Permit modification to the Company to construct and operate two 120 MW natural gas-fired turbines. The Part 70 Air Permit set emissions limits for the criteria

24

LOUISIANA GENERATING LLC

air pollutants, including NOx, based on the application of Best Available Control Technology, or BACT. The BACT limitation for NOx 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 on September 8, 2002, which is, in part, subject to the referenced administrative hearing. DEQ alleged violations related to NOx emissions. The Company denied those allegations and will contest any future penalty assessment, while also seeking an amendment of its limit for NOx. Quarterly status reports are being submitted to an Administrative Law Judge. In late February 2004, the Company timely submitted to the DEQ an amended BACT analysis and amended Prevention of Significant Deterioration and Title V permit application to amend the NOx limit, which application is pending. The Company may also assert breached warranty claims against the manufacturer.

Travis Ballou, et. al. v. Ralph Mabey, et. al., No. 03-30343 in the United States Court of Appeals for the Fifth Circuit
Kenneth Austin, et.al v. Ralph Mabey, et. al., No. 00-728-D-1 in the United States District Court for the Middle District of Louisiana

     Two lawsuits against the Company 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, which included four plaintiffs, was dismissed on summary judgment. The District Court’s summary judgment ruling was affirmed by the U.S. Court of Appeals for the Fifth Circuit on February 10, 2005. On May 9, 2005, the District Court granted six additional motions for summary judgment. In the remaining lawsuit involving 35 plaintiffs, the District Court has granted the Company’s Motions for Summary Judgment pertaining to nineteen plaintiffs, denied the Company’s Motions for Summary Judgment pertaining to four plaintiffs and is still considering the Company’s Motions for Summary Judgment pertaining to the remaining twelve plaintiffs.

BNSF Railway Company v. Louisiana Generating LLC, Case No. 531992, 19^th Judicial District Court, Parish of East Baton Rouge (filed May 6, 2005)

This lawsuit alleges breach of the coal transportation contract that expired on March 31, 2005. Specifically, the plaintiff alleges the shipment of coal via another carrier in 2004 and the failure to tender a minimum amount of coal during 2003, and further alleges that both actions constituted a breach of the contract. An accrual has been established.

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

     Pursuant to the requirements of Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies,” and related guidance, the Company records reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss is reasonably estimable. Management has assessed each of these matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought and the probability of success. Management’s judgment may, as a result of facts arising prior to resolution of these matters or other factors, prove inaccurate and investors should be aware that such judgment is made subject to the known uncertainty of litigation.

14. Regulatory Issues

     The Company’s assets are located within the franchise territory of Entergy Corporation, or Entergy, a vertically integrated utility. The utility performs the scheduling, reserve and reliability functions that are administered by the Independent System Operator, or ISO, or Regional Transmission Organizations, or RTO, in certain other regions of the United States. The Company operates a National Electric Reliability Council, or NERC, certified control area within the Entergy franchise territory, which is comprised of most 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, or FERC, approved tariff rates. Included with these transmission services are the reserve and ancillary costs. Energy prices in the South Central region are determined and agreed to in bilateral negotiations between

25

LOUISIANA GENERATING LLC

representatives of the transacting counter-parties, using market information gleaned by the individual marketing agents arranging the transactions.

     On March 31, 2004, Entergy filed with FERC a proposal to have an independent coordination of transmission, or ICT, monitor Entergy’s operation of its transmission system to review the pricing structure for transmission expansion and oversee a proposed weekly procurement process by which Entergy and other load serving entities could purchase energy. On March 22, 2005, FERC approved the ICT proposal for a two year period, subject to certain conditions. On May 27, 2005, Entergy filed its detailed ICT proposal with FERC. On December 17, 2004, FERC ordered that an investigation and evidentiary hearing be held on the issue of whether Entergy is providing access to its transmission system in a just and reasonable manner. On March 22, 2005, FERC suspended the hearing.

15. 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. All variable costs are incurred 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, 2004 and 2003, was $182.8 million and $183.2 million, respectively and the corresponding accumulated depreciation and amortization was $11.5 million and $0.5 million at December 31, 2004 and 2003, respectively.

16. 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 subsequent to the Big Cajun II facilities removal from service. On July 1, 1989, a guarantor trust fund, or Solid Waste Disposal Trust Fund, was established to accumulate the estimated funds necessary for such purpose. The Company’s predecessor deposited $1.1 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. At December 31, 2004 and 2003, the carrying value of the trust fund investments was approximately $5.0 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 the Company’s calculation of the asset retirement obligation discussed in Note 7.

17. Guarantees

     In November 2002, the FASB issued FASB Interpretation No. 45, or FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”. In connection with the adoption of Fresh Start, all outstanding guarantees were considered new; accordingly, the Company applied the provisions of FIN 45 to all of the 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.

     NRG Energy’s payment obligations under the notes and all related Parity Lien Obligations are guaranteed on an unconditional basis by certain of NRG Energy’s current and future restricted subsidiaries (other than certain excluded project subsidiaries, foreign subsidiaries and certain other 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.

     On December 24, 2004, NRG Energy’s credit facility was amended and restated, or the Amended Credit Facility, whereby NRG

26

LOUISIANA GENERATING LLC

Energy repaid outstanding amounts and issued a $450.0 million, seven-year senior secured term loan facility, a $350.0 million funded letter of credit facility, and a three-year revolving credit facility in an amount up to $150.0 million. The Amended 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 NRG Energy and certain of NRG’s current and future subsidiaries, including the Company.

     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	$	1,725,000	Obligations under credit agreement		2013	Nonperformance
NRG Energy Amended and Restated Credit Agreement	$	800,000	Obligations under credit agreement		2011	Nonperformance

     On February 4, 2005, NRG Energy redeemed and retired $375.0 million of Second Priority Notes. As a result of the retirement, the joint and several payment and performance guarantee obligation of the Company was reduced from $1,725.0 million to $1,350.0 million.

18. Income Taxes

     The Company is included in the consolidated income tax return filings of NRG Energy. Reflected in the financial statements and notes below are federal and state income tax provisions, as if the Company had prepared separate filings. The Company’s ultimate parent, NRG Energy, does not have a tax allocation agreement with its subsidiaries. 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 provision (benefit) for income taxes consists of the following:

	Reorganized Company						Predecessor Company
				For the			For the
				Period from			Period from
	For the Year			December 6,			January 1,			For the Year
	Ended			2003 to			2003 to			Ended
	December 31,			December 31,			December 5,			December 31,
	2004			2003			2003			2002
	(In thousands of dollars)
Current
Federal	$	—		$	—		$	—		$	—
State		—			—			—			—
		—			—			—			—
Deferred
Federal	$	19,090			250			(7,029	)		6,958
State		4,743			62			(1,747	)		1,729
		23,833			312			(8,776	)		8,687
Total income tax expense (benefit)	$	23,833		$	312		$	(8,776	)	$	8,687
Effective tax rate		40.2	%		40.6	%		39.8	%		68.6	%

27

LOUISIANA GENERATING LLC

The pre-tax income (loss) was as follows:

	Reorganized Company				Predecessor Company
			For the		For the
	For the		Period from		Period from			For the
	Year		December 6,		January 1,			Year
	Ended		2003 to		2003 to			Ended
	December 31,		December 31,		December 5,			December 31,
	2004		2003		2003			2002
	(In thousands of dollars)
U.S.	$	59,251	$	768	$	(22,025	)	$	12,664

     The components of the net deferred income tax (assets) liabilities were:

	Reorganized Company
	December 31,			December 31,
	2004			2003
	(In thousands of dollars)
Deferred tax liabilities
Property	$	98,048		$	32,769
Emissions credits		30,119			37,810
Development costs		—			—
Other		19			99
Total deferred tax liabilities		128,186			70,678
Deferred tax assets
Deferred compensation, accrued vacation and other reserves		572			3,371
Development costs		4,486			5,660
Difference between book and tax basis out-of-market contracts		139,080			148,892
Domestic tax loss carryforwards		90,482			41,194
Asset retirement obligation		887			829
Other		16			1,902
Total deferred tax assets (before valuation allowance)		235,523			201,848
Valuation allowance		(107,337	)		(131,170	)
Net deferred tax assets		128,186			70,678
Net deferred tax liabilities	$	—		$	—

     The net deferred income tax (assets) liabilities consist of:

	Reorganized Company
	December 31,		December 31,
	2004		2003
	(In thousands of dollars)
Current deferred tax assets	$	—	$	—
Noncurrent deferred tax liabilities	$	—	$	—
Net deferred tax liabilities	$	—	$	—

     In assessing the realizabilty of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The realization of deferred tax assets is dependent upon the generation of taxable income in future periods. Management considers both positive and negative evidence, projected operating income and capital gains, and available tax planning strategies in making this assessment. Based upon projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Company will realize the benefits of these net deferred tax assets as of December 31, 2004.

     In connection with the Company’s emergence from bankruptcy, the 2003 net operating loss carryforward was effectively increased as a result of the Company’s election in 2004 to reduce the tax basis of property on a going forward basis. This election was made in 2004 in connection with tax planning strategies for future periods and accordingly was recorded subsequent to the period ended December 31, 2003.

     During 2004, the Company utilized $59.3 million of U.S. net operating losses carryforward of $284.3 million. There is a net carryforward amount of $225.0 million available at December 31, 2004, which will expire by 2023 if unutilized.

28

LOUISIANA GENERATING LLC

     Subsequently recognized tax benefits relating to the valuation allowance for deferred tax assets as of December 31, 2004, will be allocated to intangible 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
	For the				Period from				Period from					For the
	Year				December 6,				January 1,					Year
	Ended				2003 to				2003 to					Ended
	December 31,				December 31,				December 5,					December 31,
	2004				2003				2003					2002
	(In thousands of dollars)
Income (loss) before taxes	$	59,251			$	768			$	(22,025	)			$	12,664
Tax at 35%		20,738	35.0	%		269	35.0	%		(7,709	)	35.0	%		4,432	35.0	%
State taxes (net of federal benefit)		3,083	5.2	%		40	5.2	%		(1,135	)	5.2	%		1,124	8.9	%
Other		12	—	%		3	0.4	%		68		(0.3	)%		3,131	24.7	%
Income tax expense (benefit)	$	23,833	40.2	%	$	312	40.6	%	$	(8,776	)	39.9	%	$	8,687	68.6	%

29

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON
FINANCIAL STATEMENT SCHEDULE

To the Member of
Louisiana Generating LLC:

     Our audits of the financial statements referred to in our reports 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, the period from January 1, 2003 to December 5, 2003 and for the year 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

30

LOUISIANA GENERATING LLC

SCHEDULE II. VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2004, 2003 and 2002

			Column C
	Column B		Additions						Column E
	Balance at		Charged to						Balance at
Column A	Beginning of		Costs and		Charged to		Column D		End of
Description	Period		Expenses		Other		Deductions		Period
	(In thousands)
Income tax valuation allowance, deducted from deferred tax assets in the balance sheet:
Reorganized Company Year Ended December 31, 2004	$	131,170	$	—	$	—	$	23,833	$	107,337
December 6 - December 31, 2003	$	131,482		—		—		312		131,170
Predecessor Company
January 1 - December 5, 2003		—		—		131,482		—		131,482	*
Year Ended December 31, 2002		—		—		—		—		—
* December 6, 2003 - Fresh Start Balance

31

EX-99.4

EXHIBIT 99.4

NRG MID ATLANTIC GENERATING LLC AND SUBSIDIARIES

CONSOLIDATED FINANCIAL STATEMENTS

At December 31, 2004 and 2003,
and for the Year Ended December 31, 2004,
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

1

NRG MID ATLANTIC GENERATING LLC AND SUBSIDIARIES

INDEX

	Page
Reports of Independent Registered Public Accounting Firms		3
Consolidated Balance Sheets at December 31, 2004 and 2003		6
Consolidated Statements of Operations for the year ended December 31, 2004, 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		7
Consolidated Statements of Member’s Equity and Comprehensive Income for the year ended December 31, 2004, 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		8
Consolidated Statements of Cash Flows for the year ended December 31, 2004, 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		9
Notes to Consolidated Financial Statements		10

2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Member of
NRG Mid Atlantic Generating LLC

     We have audited the accompanying consolidated balance sheet of NRG Mid Atlantic Generating LLC and its subsidiaries as of December 31, 2004, and the related consolidated statements of operations, member’s equity and comprehensive income, and cash flows for the year then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

     We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

     In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of NRG Mid Atlantic Generating LLC and its subsidiaries as of December 31, 2004, and the results of their operations and their cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles.

/S/	KPMG LLP
	KPMG LLP

Philadelphia, Pennsylvania
May 27, 2005

3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Member of
NRG Mid Atlantic Generating LLC

     In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, of member’s equity and comprehensive income, 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 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 audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 audit provides a reasonable basis for our opinion.

     As discussed in Notes 1 and 2 to the financial statements, on May 14, 2003 NRG Energy, Inc. and certain of its subsidiaries, excluding 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 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

4

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Member of
NRG Mid Atlantic Generating LLC

     In our opinion, the accompanying consolidated statements of operations, of member’s equity and comprehensive income, and of cash flows present fairly, in all material respects, the results of operations and cash flows of NRG Mid Atlantic Generating LLC and its subsidiaries (“Predecessor Company”) for the period from January 1, 2003 to December 5, 2003 and for the year 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). 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 Notes 1 and 2 to the financial statements, on May 14, 2003 NRG Energy, Inc. and certain of its subsidiaries, excluding 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 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

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NRG MID ATLANTIC GENERATING LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	Reorganized Company
	December 31,		December 31,
	2004		2003
	(In thousands of dollars)
ASSETS
Current assets
Cash and cash equivalents	$	545	$	77
Accounts receivable, net of allowance for doubtful accounts of $0		1,160		—
Accounts receivable — affiliates		10,055		5,155
Inventory		19,800		17,611
Derivative instruments valuation		13,946		161
Prepayments and other current assets		2,105		2,385
Total current assets		47,611		25,389
Property, plant and equipment, net of accumulated depreciation of $27,765 and $1,693, respectively		548,223		565,201
Investment in projects		1,280		1,280
Intangible assets, net of accumulated amortization of $3,817 and $0, respectively		60,754		68,469
Noncurrent derivative instrument valuation		1,124		—
Other assets		6,924		6,753
Total assets	$	665,916	$	667,092
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Current portion of capital lease	$	16	$	—
Accounts payable — trade		9		38
Accounts payable — affiliates		—		259
Accrued expenses		215		142
Derivative instruments valuation		2,355		163
Current deferred income tax		—		56
Other current liabilities		102		285
Total current liabilities		2,697		943
Long term capital lease		202		—
Noncurrent derivative instrument valuation		25		—
Noncurrent deferred income tax		47,045		32,979
Other long-term obligations		4,576		4,256
Total liabilities		54,545		38,178
Commitments and contingencies
Member’s equity		611,371		628,914
Total liabilities and member’s equity	$	665,916	$	667,092

The accompanying notes are an integral part of these consolidated financial statements.

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NRG MID ATLANTIC GENERATING LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Reorganized Company					Predecessor Company
			For the			For the
			Period from			Period from
	For the Year		December 6,			January 1,			For the Year
	Ended		2003 to			2003 to			Ended
	December 31,		December 31,			December 5,			December 31,
	2004		2003			2003			2002
	(In thousands of dollars)
Revenues	$	219,080	$	7,580		$	175,933		$	242,015
Operating costs		147,977		6,317			117,753			97,830
Depreciation		26,152		1,693			29,145			29,530
General and administrative expenses		14,403		1,225			3,518			5,856
Restructuring charges		—		—			1,599			—
Income (loss) from operations		30,548		(1,655	)		23,918			108,799
Interest expense		—		(873	)		(18,740	)		(16,022	)
Other income (expense), net		1,402		47			1,053			132
Income (loss) before income taxes		31,950		(2,481	)		6,231			92,909
Income tax expense (benefit)		12,987		(1,008	)		2,532			38,097
Net income (loss)	$	18,963	$	(1,473	)	$	3,699		$	54,812

The accompanying notes are an integral part of these consolidated financial statements.

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NRG MID ATLANTIC GENERATING LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY AND COMPREHENSIVE INCOME

											Accumulated
					Member’s			Accumulated			Other		Total
	Member’s				Contributions/			Net Income/			Comprehensive		Member’s
	Units		Amount		Distributions			(Loss)			Income		Equity
					(In thousands of dollars)
Balances at December 31, 2001 (Predecessor Company)		1,000	$	1	$	190,725		$	33,661		$	—	$	224,387
Net income		—		—		—			54,812			—		54,812
Balances at December 31, 2002 (Predecessor Company)		1,000		1		190,725			88,473			—		279,199
Net income		—		—		—			3,699			—		3,699
Contribution from member		—		—		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 member		—		—		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
Impact of SFAS 133 for the year ending December 31, 2004, net of income taxes of $1,023		—		—		—			—			1,495		1,495
Net income		—		—		—			18,963			—		18,963
Comprehensive income		—		—		—			—			—		20,458
Distribution to member		—		—		(20,511	)		(17,490	)		—		(38,001	)
Balances at December 31, 2004 (Reorganized Company)		1,000	$	1	$	609,875		$	—		$	1,495	$	611,371

The accompanying notes are an integral part of these consolidated financial statements.

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NRG MID ATLANTIC GENERATING LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

	Reorganized Company						Predecessor Company
				For the			For the
				Period from			Period from
	For the Year			December 6,			January 1,			For the Year
	Ended			2003 to			2003 to			Ended
	December 31,			December 31,			December 5,			December 31,
	2004			2003			2003			2002
				(In thousands of dollars)
Cash flows from operating activities
Net income (loss)	$	18,963		$	(1,473	)	$	3,699		$	54,812
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation		26,152			1,693			29,145			29,530
Amortization of intangibles		3,817			—			—			—
Loss on disposal of assets		1,267			—			—			—
Amortization of power contracts		—			—			—			(89,251	)
Unrealized (gain) loss on derivatives		(10,174	)		163			3,892			(4,442	)
Amortization of debt issuance costs		—			—			1,607			2,345
Deferred income taxes		12,987			(1,008	)		2,532			38,097
Changes in assets and liabilities
Accounts receivable		(1,160	)		—			15,733			2,592
Accounts receivable — affiliates		(4,900	)		1,235			(6,390	)		—
Inventory		(2,189	)		(2,770	)		9,060			4,569
Prepayments and other current assets		280			438			9,709			(10,220	)
Other assets		(171	)		(4	)		(6,749	)		—
Accounts payable — trade		(29	)		(20	)		(408	)		(2,552	)
Accounts payable — affiliates		(259	)		228			(108,456	)		38,861
Accrued interest		—			(3,269	)		3,207			(2,769	)
Changes in other assets and liabilities		4,108			(148	)		(986	)		1,692
Net cash provided by (used in) operating activities		48,692			(4,935	)		(44,405	)		63,264
Cash flows from investing activities
Decrease (increase) in restricted cash		—			80,306			(42,380	)		(37,926	)
Investment in projects		—			—			(1,280	)		—
Capital expenditures		(10,218	)		(1,194	)		(14,237	)		(13,546	)
Net cash (used in) provided by investing activities		(10,218	)		79,112			(57,897	)		(51,472	)
Cash flows from financing activities
Bank overdraft		—			—			—			(100	)
Payments on long-term borrowings and capital leases		(5	)		(406,560	)		(2,641	)		(11,692	)
Contribution from member		—			332,460			104,943			—
Distribution to member		(38,001	)		—			—			—
Net cash (used in) provided by financing activities		(38,006	)		(74,100	)		102,302			(11,792	)
Net change in cash and cash equivalents		468			77			—			—
Cash and cash equivalents
Beginning of period		77			—			—			—
End of period	$	545		$	77		$	—		$	—
Supplemental disclosures of cash flow information
Capital lease obligations incurred	$	223
Cash paid for interest	$	—		$	4,093		$	13,860		$	18,791

The accompanying notes are an integral part of these consolidated financial statements.

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NRG MID ATLANTIC GENERATING LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization

     NRG Mid Atlantic Generating LLC, or the Company, a wholly owned subsidiary of NRG Energy, Inc., or NRG Energy, owns electric power generation plants in the mid-atlantic region of the United States. 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, or Indian River; Vienna Power LLC, or Vienna; Keystone Power LLC, or Keystone; and Conemaugh Power LLC, or Conemaugh.

     From May 14 to December 23, 2003, NRG Energy and a number of its subsidiaries, excluding the Company, undertook a comprehensive reorganization and restructuring under chapter 11 of the United States Bankruptcy Code.

2. Summary of Significant Accounting Policies

   Principles of Consolidation and Basis of Presentation

     For financial reporting purposes, close of business on December 5, 2003, represents the date of NRG Energy’s emergence from bankruptcy. 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 NRG Energy’s emergence from bankruptcy
	The Company’s operations prior to December 6, 2003
“Reorganized Company”	The Company, after NRG Energy’s emergence from bankruptcy
	The Company’s operations, December 6, 2003 — December 31, 2004

     The consolidated financial statements include the accounts of the Company and its subsidiaries in which we have a controlling interest. All significant intercompany transactions and balances have been eliminated in consolidation.

   Fresh Start Reporting/Push Down Accounting

     In accordance with SOP 90-7, 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 immediately before confirmation receive less than 50 percent of the voting shares of the emerging entity. NRG Energy met these requirements and adopted Fresh Start reporting resulting in the creation of a new reporting entity designated as Reorganized NRG. 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.

     The bankruptcy court issued a confirmation order approving 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. The Xcel Energy settlement agreement was entered into on December 5, 2003. NRG Energy 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.

     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, or SFAS, No. 109, “Accounting for Income Taxes”. The net effect of all Fresh Start adjustments resulted in a gain of $3.9 billion (comprised of a $4.1 billion gain from

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NRG MID ATLANTIC GENERATING LLC AND SUBSIDIARIES

continuing operations and a $0.2 billion loss from discontinued operations), 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 and push down accounting 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 NRG Energy’s 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 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. 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.

     Due to the adoption of Fresh Start upon NRG Energy’s emergence from bankruptcy and the impact of push down accounting, the Reorganized Company’s 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.

   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.

   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. On December 5, 2003, the Company 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 calculated using the straight-line method over the following 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.

Facilities and equipment 2 to 40 years

   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

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NRG MID ATLANTIC GENERATING LLC AND SUBSIDIARIES

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.

   Intangible Assets

     Intangible assets represent contractual rights held by the Company. Intangible assets are amortized overt their economic useful life and reviewed for impairment whenever events or changes in circumstances indicate carrying values may not be recoverable.

     Intangible assets consist of the fair value of emission allowances. Emission allowance related amounts are amortized as additional fuel expense based upon the actual level of emissions from the respective plants through 2023.

   Fair Value of Financial Instruments

     The carrying amount of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate fair value because of the short maturity of these instruments. The fair value of capital leases are 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. However, a provision for 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 income taxes payable amounts resulting from the tax provision are reflected as a contribution by member in the consolidated statement of member’s 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.

   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. Electric energy revenue is recognized upon transmission to the customer. 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, or 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 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. See Note 14 — Related Party Transactions.

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NRG MID ATLANTIC GENERATING LLC AND SUBSIDIARIES

   Credit Risk

     Credit risk relates to the risk of loss resulting from non-performance or non-payment by counter-parties pursuant to the terms of their contractual obligations. NRG Energy monitors and manages the credit risk of its affiliates including the Company and its subsidiaries, through credit policies which include an (i) established credit approval process, (ii) daily monitoring of counter-party credit limits, (iii) the use of credit mitigation measures such as margin, collateral, credit derivatives or prepayment arrangements, (iv) the use of payment netting agreements and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counter-party. Risk surrounding counter-party performance and credit could ultimately impact the amount and timing of expected cash flows. NRG Energy has credit protection within various agreements to call on additional collateral support if necessary.

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

   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, disclosure of contingent 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.

   Recent Accounting Pronouncements

     In November 2004, the FASB issued SFAS No. 151, “Inventory Costs- an amendment of ARB No. 43, Chapter 4”. This statement amends the guidance in Accounting Research Bulletin No. 43, Chapter 4, “Inventory Pricing”, and requires that idle facility expense, excessive spoilage, double freight, and rehandling costs be recognized as current-period charges regardless of whether they meet the criteria of “so abnormal” established by ARB No. 43. SFAS No.151 is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The Company is currently in the process of evaluating the potential impact that the adoption of this statement will have on the consolidated financial position and results of operations.

     In December 2004, the FASB issued two FASB Staff Positions, or FSPs, regarding the accounting implications of the American Jobs Creation Act of 2004 related to (1) the deduction for qualified domestic production activities (FSP FAS 109-1) and (2) the one-time tax benefit for the repatriation of foreign earnings (FSP FAS 109-2). In FSP FAS 109-1, “Application of FASB Statement No. 109, “Accounting for Income Taxes,” to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004”, the Board decided that the deduction for qualified domestic production activities should be accounted for as a special deduction under FASB Statement No. 109, “Accounting for Income Taxes” and rejected an alternative view to treat it as a rate reduction. Accordingly, any benefit from the deduction should be reported in the period in which the deduction is claimed on the tax return. FSP FAS 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004”, addresses the appropriate point at which a company should reflect in its financial statements the effects of the one-time tax benefit on the repatriation of foreign earnings. Because of the proximity of the Act’s enactment date to many companies’ year-ends, its temporary nature, and the fact that numerous provisions of the Act are sufficiently complex and ambiguous, the Board decided that absent additional clarifying regulations, companies may not be in a position to assess the impact of the Act on their plans for repatriation or reinvestment of foreign earnings. Therefore, the Board provided companies with a practical exception to FAS 109’s requirements by providing them additional time to determine the amount of earnings, if any, that they intend to repatriate under the Act’s beneficial provisions. The Board confirmed, however, that upon deciding that some amount of earnings will be repatriated, a company must record in that period the associated tax liability, thereby making it clear that a company cannot avoid recognizing a tax liability when it has decided that some portion of its foreign earnings will be repatriated. The Company is currently

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NRG MID ATLANTIC GENERATING LLC AND SUBSIDIARIES

in the process of evaluating the potential impact that the adoption of FSP FAS 109-1 will have on our consolidated financial position and results of operations. The Company does not believe that the potential adoption of FSP 109-2 will have a material impact on our consolidated financial position and results of operation.

     In March 2005, the Financial Accounting Standards Board (FASB) issued Interpretation No. 47 (FIN 47) to Financial Accounting Standard No. 143 (SFAS No. 143) governing the application of Asset Retirement Obligations. FIN 47 clarifies that the term “conditional asset retirement obligation” as used in SFAS 143. SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional but there may remain some uncertainty as to the timing and/or method of settlement. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred — generally upon acquisition, construction, or development and/or through the normal operation of the asset. SFAS No. 143 acknowledges that in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation. FIN 47 clarifies when the company would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective for fiscal years ending after December 15, 2005 and we are currently evaluating the impact of this guidance.

3. Emergence from Bankruptcy and Fresh Start Reporting

     In accordance with the requirements of SFAS No. 141 “Business Combinations,” and push down accounting, the Company’s fair value of $297.9 million as of the Fresh Start date 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 fresh start 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 fresh start.

     The effects of the push down accounting adjustments on the Company’s condensed 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)
Current Assets	$	108,280	$	(3,759	)	$	104,521
Non-current Assets		795,735		(153,537	)		642,198
Total Assets	$	904,015	$	(157,296	)	$	746,719
Current Liabilities	$	410,517	$	56		$	410,573
Non-current Liabilities		105,657		(67,438	)		38,219
		516,174		(67,382	)		448,792
Members’ Equity		387,841		(89,914	)		297,927
Total Liabilities and Member’s Equity	$	904,015	$	(157,296	)	$	746,719

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:

	Reorganized Company
	December 31,		December 31,
	2004		2003
	(In thousands of dollars)
Fuel oil	$	2,165	$	2,601
Spare parts		5,329		5,188
Coal		12,306		9,822
Total inventory	$	19,800	$	17,611

14

NRG MID ATLANTIC GENERATING LLC AND SUBSIDIARIES

6. Property, Plant and Equipment

     The major classes of property, plant and equipment were as follows:

		Reorganized Company						Average
	Depreciable	December 31,			December 31,			Remaining
	Lives	2004			2003			Useful Life
		(In thousands of dollars)
Land		$	19,452		$	19,386
Facilities and equipment	2-40 years		555,214			536,925		19 years
Construction work in progress			1,322			10,583
Total property, plant and equipment			575,988			566,894
Accumulated depreciation			(27,765	)		(1,693	)
Property, plant and equipment, net		$	548,223		$	565,201

7. Asset Retirement Obligations

     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 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 and the year ended December 31, 2004, 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.

	Reorganized Company
			Accretion for
			Period				Accretion for
			December 6,		Ending		the Year				Ending
	Beginning		2003 to		Balance		Ended				Balance
	Balance		December 31,		December 31,		December 31,				December 31,
	December 6, 2003		2003		2003		2004		Additions		2004
	(In thousands of dollars)
Indian River landfill closure obligation	$	4,198	$	24	$	4,222	$	294	$	—	$	4,516
Conemaugh compost closure obligation		—		—		—		—		36		36
Keystone compost closure obligation		—		—		—		—		9		9
	$	4,198	$	24	$	4,222	$	294	$	45	$	4,561

	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

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NRG MID ATLANTIC GENERATING LLC AND SUBSIDIARIES

8. Intangible Assets

Reorganized Company

     Upon the adoption of Fresh Start and application of push down accounting, the Company established intangible assets for plant emissions allowances. These intangible assets are amortized over their lives based on a units of production basis. Emission allowances are amortized as additional fuel expense based upon the actual level of emissions from the respective plants through 2023. Aggregate amortization expense for the year ended December 31, 2004 and period from December 6, 2003 through December 31, 2003 was approximately $2.9 million and $0 million, respectively. The annual aggregate amortization expense for each of the five succeeding years is expected to approximate $2.9 million in 2005 and 2006, $3.0 million in 2007, $3.0 million in 2008, and $2.8 million 2009. Intangible assets were reduced by $3.9 million during 2004 related to a true-up of certain tax evaluations.

     Intangible assets consisted of the following:

	Emission
	Allowances
	(In thousands
	of dollars)
Balance at December 31, 2003	$	68,469
Amortization		(3,817	)
Other adjustments		(3,898	)
Balance at December 31, 2004	$	60,754

Predecessor Company

     The Company had no intangible assets 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.

10. Out of Market Contracts

     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 was comprised of three out-of-market contracts, two of which were less than one year in duration from the acquisitions date and the third contract was originally in effect through 2005. Upon the acquisition, the Company assumed the remaining obligations under these 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 out-of-market contract liability was amortized into revenue based on the terms of the power purchase agreements. Accordingly, the Company recognized $89.3 million in revenues associated with the amortization of the long-term and short-term power purchase agreements, during the year ended December 31, 2002.

     On November 8, 2002, Conectiv provided NRG Energy with a Notice of Termination of Transaction under the Master Power Purchase and Sale Agreement, or 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.

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NRG MID ATLANTIC GENERATING LLC AND SUBSIDIARIES

11. Sales to Significant Customers

     The Company derives revenues from four significant customers:

	Reorganized Company						Predecessor Company
				For the			For the
				Period from			Period from
	For the			December 6,			January 1,			For the
	Year Ended			2003 to			2003 to			Year Ended
	December 31,			December 31,			December 5,			December 31,
	2004			2003			2003			2002
				(Percent of total revenues)
Sales to:
Atlantic City Electric, dba Conectiv		28.4	%		38.0	%		60.0	%		96.0	%
Jersey Central Power & Light		13.0	%		—	%		—	%		—	%
Rockland Electric		11.3	%		13.0	%		—	%		—	%
PJM Interconnection		29.6	%		49.0	%		27.0	%		—	%

12. Capital Lease

     In September 2004, Conemaugh entered into a capital lease for equipment. The lease extends for 10 years. Monthly payments under the lease are $2,591. The balance at December 31, 2004 was $0.2 million.

13. Derivative Instruments and Hedging Activity

     SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” as amended by SFAS No. 137, SFAS No. 138 and SFAS No. 149 requires the Company to recognize all derivative instruments on the balance sheet as either assets or liabilities and measure them at fair value each reporting period. If certain conditions are met, the Company may be able to designate derivatives as cash flow hedges and defer the effective portion of the change in fair value of the derivatives in Accumulated Other Comprehensive Income and subsequently recognize in earnings when the hedged items impact income. The ineffective portion of a cash flow hedge is immediately recognized in income.

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

     For derivatives that are neither designated as cash flow hedges or do not qualify for hedge accounting treatment, the changes in the fair value will be immediately recognized in earnings.

     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, 2004, the Company had various commodity contracts extending through December 2006. 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.

     The Company’s earnings for the year ended December 31, 2004, the period from December 6, 2003 through December 31, 2003, the period from January 1, 2003 through December 5, 2003 and the year ended December 31, 2002, were increased (decreased) by unrealized gains (losses) of $10.2 million, ($0.2) million, ($3.9) million and $4.4 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.

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NRG MID ATLANTIC GENERATING LLC AND SUBSIDIARIES

   Accumulated Other Comprehensive Income

     The following table summarizes the effects of SFAS No. 133, as amended, on the Company’s accumulated other comprehensive income balance for the year ended December 31, 2004, 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:

	Reorganized Company					Predecessor Company
				For the		For the
				Period from		Period from
	For the			December 6,		January 1,		For the
	Year Ended			2003 to		2003 to		Year Ended
	December 31,			December 31,		December 5,		December 31,
	2004			2003		2003		2002
	(In thousands of dollars)
Energy Commodities Gains (Losses)
Beginning accumulated OCI balance	$	—		$	—	$	—	$	—
Unwound from OCI during period due to unwinding of previously deferred amounts		—			—		—		—
Mark to market of hedge contracts		2,518			—		—		—
Tax effect		(1,023	)		—		—		—
Ending accumulated OCI balance	$	1,495		$	—	$	—	$	—
Gains expected to unwind from accumulated OCI during next 12 months	$	1,495

     During the year ended December 31, 2004 the Company recorded pre-tax gains in OCI of $2.5 million related to changes in the fair values of derivatives accounted for as hedges.

   Statement of Operations

     The following table summarizes the pre-tax effects of non hedge derivatives and derivatives that no longer qualify as hedges on the Company’s statement of operations for the year ended December 31, 2004, 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:

	Reorganized Company						Predecessor Company
				For the			For the
				Period from			Period from
	For the Year			December 6,			January 1,			For the Year
	Ended			2003 to			2003 to			Ended
	December 31,			December 31,			December 5,			December 31,
	2004			2003			2003			2002
	(In thousands of dollars)
Gains (Losses)
Revenues	$	10,262		$	(163	)	$	(994	)	$	1,052
Costs of operations		(88	)		—			(2,898	)		3,390
Total statement of operations impact before tax	$	10,174		$	(163	)	$	(3,892	)	$	4,442

   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.

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NRG MID ATLANTIC GENERATING LLC AND SUBSIDIARIES

14. Related Party Transactions

     On June 22, 2001, Indian River, Vienna, Keystone and Conemaugh entered into energy marketing services agreement with NRG Power Marketing Inc., or NRG Power Marketing, a wholly owned subsidiary of NRG Energy. The agreements are effective for consecutive one-year terms until terminated by either party upon 90 days written notice before the end of any such term. Under the agreement, NRG Power Marketing and its wholly owned subsidiary, NJ Energy Sales, will (i) have the exclusive right to manage, purchase 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.

     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 costs, taxes, employee labor, contract services, etc.). The Company incurred no fees related to this energy marketing services agreement 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., or 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 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. These costs are reflected in operating costs in the consolidated statements of operations.

     For the year ended December 31, 2004, Indian River and Vienna incurred operating and maintenance costs billed from NRG Operating Services totaling $44.5 million and $4.4 million, respectively. 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.

     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. For the year ended December 31, 2004, Indian River and Vienna incurred expenses of $5.5 million and $1.7 million respectively. During the period from December 6, 2003 to December 31, 2003, Indian River and Vienna incurred expenses of

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NRG MID ATLANTIC GENERATING LLC AND SUBSIDIARIES

$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, Indian River incurred expenses of $134,000 and Vienna incurred expenses of $57,000 under these agreements. The amounts paid for the year ended December 31, 2004 reflect an overall increase in corporate level general and administrative expenses. Corporate general, administrative and development expenses increase in 2004 due to higher legal fees, increased audit costs and increased consulting costs due to NRG Energy’s Sarbanes-Oxley implementation. The method of allocating these costs remained the same from the prior years.

At December 31, 2004 and December 31, 2003, the Company had an accounts receivable - affiliates balance of $10.1 million and $5.2 million, respectively. At December 31, 2003, the Company also had an accounts payable — affiliates balance of $0.3 million. These balances are settled on a periodic basis and are due to or from multiple entities which are wholly owned subsidiaries of NRG Energy Inc, the parent company of Mid Atlantic Generating LLC.

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 $6.7 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.

     The Company estimates that it will incur capital expenditures of approximately $22.2 million during the years 2005 through 2010 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. An asset retirement obligation has been recorded for closure of the existing ash landfills.

   Guarantees

     In November 2002, the FASB issued FASB Interpretation, or FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”. In connection with the adoption of Fresh Start, all outstanding guarantees were considered new; accordingly, the Company applied the provisions of FIN 45 to all of the guarantees.

     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 guaranteed on an unconditional basis by certain of NRG Energy’s current and future restricted subsidiaries (other than certain excluded project subsidiaries, foreign subsidiaries and certain other 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.

     On December 24, 2004, NRG Energy’s credit facility was amended and restated, or the Amended Credit Facility, whereby NRG Energy repaid outstanding amounts and issued a $450.0 million, seven-year senior secured term loan facility, a $350.0 million funded letter of credit facility, and a three-year revolving credit facility in an amount up to $150.0 million. The Amended 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 NRG Energy and certain of NRG’s current and future subsidiaries, including the following direct and indirect wholly owned subsidiaries:

Subsidiary
NRG Mid Atlantic Generating LLC (Direct)
Indian River Power LLC (Indirect)
Vienna Power LLC (Indirect)
Keystone Power LLC (Indirect)
Conemaugh Power LLC (Indirect)

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NRG MID ATLANTIC GENERATING LLC AND SUBSIDIARIES

     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	$	1,725,000	Obligations under credit agreement	2013	Nonperformance
NRG Energy Amended and Restated Credit Agreement	$	800,000	Obligations under credit agreement	2011	Nonperformance

     On February 4, 2005, NRG Energy redeemed and retired $375.0 million of Second Priority Notes. As a result of the retirement, the joint and several payment and performance guarantee obligation of the Company and the above listed subsidiaries was reduced from $1,725.0 million to $1,350.0 million.

16. Regulatory Issues

     On January 25, 2005, FERC issued an order approving the PJM proposal to increase the compensation for generators which are located in load pockets and are mitigated at least 80% of their running time. Specifically, when the generators would be subject to mitigation, the generator would have the option of recovering their variable costs plus $40 or a negotiated rate with PJM, based on the facility’s going forward costs. If the generator declines both options, it could file for an alternative rate with FERC. Some of the Company’s facilities located in PJM are impacted by the change. The revisions to the cost capping rule could impact the revenues earned by several of the Company’s facilities. In the order, FERC also substantially revised the exemption facilities built after 1996 had from the capping mitigation rule. Under the order the exemption for facilities located in original PJM territory now applies only if the facility was constructed after April 1, 1999. If construction of the facility began after September 30, 2003, the exemption would not apply. This limitation to the post 1996 exemption will probably reduce the energy clearing price, or ECP, more because units will be subject to the cost capping rule and therefore will be unable to set the ECP.

17. Income Taxes

     The Company is included in the consolidated income tax return filings of NRG Energy. Reflected in the financial statements and notes below are federal and state tax provisions, as if the Company had prepared separate filings. The Company’s ultimate parent, NRG Energy, does not have a tax allocation agreement with its subsidiaries. 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 provision (benefit) for income taxes consists of the following:

	Reorganized Company						Predecessor Company
				For the			For the
				Period from			Period from
	For the Year			December 6,			January 1,			For the Year
	Ended			2003 to			2003 to			Ended
	December 31,			December 31,			December 5,			December 31,
	2004			2003			2003			2002
	(In thousands of dollars)
Current
Federal	$	—		$	—		$	—		$	—
State		—			—			—			—
		—			—			—			—
Deferred
Federal		10,219			(793	)		1,992			29,977
State		2,768			(215	)		540			8,120
		12,987			(1,008	)		2,532			38,097
Total income tax (benefit) expense	$	12,987		$	(1,008	)	$	2,532		$	38,097
Effective tax rate		40.6	%		40.6	%		40.6	%		41.0	%

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NRG MID ATLANTIC GENERATING LLC AND SUBSIDIARIES

     The pre-tax income (loss) was as follows:

	Reorganized Company					Predecessor Company
			For the			For the
			Period from			Period from
	For the Year		December 6,			January 1,		For the Year
	Ended		2003 to			2003 to		Ended
	December 31,		December 31,			December 5,		December 31,
	2004		2003			2003		2002
	(In thousands of dollars)
U.S	$	31,950	$	(2,481	)	$	6,231	$	92,909

     The components of the net deferred income tax liability were:

	Reorganized Company
	December 31,		December 31,
	2004		2003
	(In thousands of dollars)
Deferred tax liabilities
Property	$	52,686	$	10,258
Emissions credits		22,075		27,818
Net unrealized losses on mark to market transactions		5,156		—
Other		1,013		732
Total deferred tax liabilities		80,930		38,808
Deferred tax assets
Difference between book and tax basis of contracts		1,531		—
Domestic tax loss carryforwards		29,566		3,085
Asset retirement obligation		1,857		1,715
Other		931		973
Total deferred tax assets		33,885		5,773
Net deferred tax liability	$	47,045	$	33,035

     The net deferred tax liability consists of:

	Reorganized Company
	December 31,		December 31,
	2004		2003
	(In thousands of dollars)
Current deferred tax liability	$	—	$	56
Noncurrent deferred tax liability		47,045		32,979
Net deferred tax liability	$	47,045	$	33,035

     In assessing the realizabilty of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The realization of deferred tax assets is dependent upon the generation of taxable income in future periods. Management considers both positive and negative evidence, projected operating income and capital gains, and available tax planning strategies in making this assessment. Based upon projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Company will realize the benefits of these net deferred tax assets as of December 31, 2004.

     In connection with the Company’s emergence from bankruptcy, the 2003 net operating loss carryforward was effectively increased as a result of the Company’s election in 2004 to reduce the tax basis of property on a going forward basis. This election was made in 2004 in connection with tax planning strategies for future periods and accordingly was recorded subsequent to the period ended December 31, 2003.

     In 2004, we utilized $53.6 million of U.S. net operating losses carryforward of $126.4 million. There is a net carryforward amount of $72.8 million available at December 31, 2004, which will expire by 2023 if unutilized.

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NRG MID ATLANTIC GENERATING LLC AND SUBSIDIARIES

     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
	For the Year				December 6,					January 1,				For the Year
	Ended				2003 to					2003 to				Ended
	December 31,				December 31,					December 5,				December 31,
	2004				2003					2003				2002
	(In thousands of dollars)
Income (loss) before taxes	$	31,950			$	(2,481	)			$	6,231			$	92,909
Tax at 35%		11,183	35.0	%		(868	)	35.0	%		2,180	35.0	%		32,518	35.0	%
State taxes (net of federal benefit)		1,799	5.6	%		(140	)	5.6	%		352	5.6	%		5,278	5.7	%
Other		5	—	%		—		—	%		—	—	%		301	0.3	%
Income tax (benefit) expense	$	12,987	40.6	%	$	(1,008	)	40.6	%	$	2,532	40.6	%	$	38,097	41.0	%

18.    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 Connectiv. 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 of 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 year ended December 31, 2002, the weighted average interest rate was 3.30%. The Company was obligated to pay a commitment fee of 0.375% of the unused portion of the credit facility.

23

EX-99.5

EXHIBIT 99.5

INDIAN RIVER POWER LLC

FINANCIAL STATEMENTS

At December 31, 2004 and 2003,
and for the Year Ended December 31, 2004,
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

1

INDIAN RIVER POWER LLC

INDEX

	Page
Reports of Independent Registered Public Accounting Firms		3
Balance Sheets at December 31, 2004 and 2003		6
Statements of Operations for the year ended December 31, 2004, 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		7
Statements of Member’s Equity for the year ended December 31, 2004, 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		8
Statements of Cash Flows for the year ended December 31, 2004, 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		9
Notes to Financial Statements		10

2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Member of
Indian River Power LLC

     We have audited the accompanying balance sheet of Indian River Power LLC as of December 31, 2004, and the related statements of operations, member’s equity, and cash flows for the year then ended. 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 audit.

     We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

     In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Indian River Power LLC as of December 31, 2004, and the results of its operations and its cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles.

	/S/ KPMG LLP
	KPMG LLP
Philadelphia, Pennsylvania
May 27, 2005

3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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 comprehensive income, 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 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 audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 audit provides a reasonable basis for our opinion.

     As discussed in Notes 1 and 2 to the financial statements, on May 14, 2003 NRG Energy, Inc. and certain of its subsidiaries, excluding 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 Reorganized 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

4

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Member of
Indian River Power LLC

     In our opinion, the accompanying statements of operations, of member’s equity and comprehensive income, and of cash flows present fairly, in all material respects, the results of operations and cash flows of Indian River Power LLC (“Predecessor Company”) for the period from January 1, 2003 to December 5, 2003 and for the year 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). 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 Notes 1 and 2 to the financial statements, on May 14, 2003 NRG Energy, Inc. and certain of its subsidiaries, excluding 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 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

5

INDIAN RIVER POWER LLC

BALANCE SHEETS

	Reorganized Company
	December 31,		December 31,
	2004		2003
	(In thousands of dollars)
ASSETS
Current assets
Accounts receivable, net of allowance for doubtful accounts of $0	$	1,160	$	—
Accounts receivable — affiliates		6,330		—
Inventory		16,320		13,702
Prepayments and other current assets		1,510		1,171
Total current assets		25,320		14,873
Property, plant and equipment, net of accumulated depreciation of $18,538 and $1,080, respectively		385,097		395,021
Intangible assets, net of accumulated amortization of $2,913 and $0, respectively		51,325		57,531
Other assets		6,738		6,668
Total assets	$	468,480	$	474,093
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable — trade	$	4	$	3
Accounts payable — affiliates		—		59,734
Accrued expenses		125		142
Current deferred income tax		—		44
Other current liabilities		—		40
Total current liabilities		129		59,963
Deferred income tax		22,160		15,144
Other long-term obligations		4,531		4,256
Total liabilities		26,820		79,363
Commitments and contingencies
Member’s equity		441,660		394,730
Total liabilities and member’s equity	$	468,480	$	474,093

The accompanying notes are an integral part of these financial statements.

6

INDIAN RIVER POWER LLC

STATEMENTS OF OPERATIONS

	Reorganized Company					Predecessor Company
			For the			For the
			Period from			Period from
	For the Year		December 6,			January 1,			For the Year
	Ended		2003 to			2003 to			Ended
	December 31,		December 31,			December 5,			December 31,
	2004		2003			2003			2002
			(In thousands of dollars)
Revenues	$	165,479	$	4,925		$	136,361		$	200,170
Operating costs		123,575		4,882			90,717			76,265
Depreciation		17,538		1,080			22,972			23,097
General and administrative expenses		8,571		942			1,872			2,242
Income (loss) from operations		15,795		(1,979	)		20,800			98,566
Interest expense		—		(667	)		(14,303	)		(10,830	)
Other income, net		1,264		6			143			90
Income (loss) before income taxes		17,059		(2,640	)		6,640			87,826
Income tax expense (benefit)		6,972		(1,078	)		2,712			34,926
Net income (loss)	$	10,087	$	(1,562	)	$	3,928		$	52,900

The accompanying notes are an integral part of these financial statements.

7

INDIAN RIVER POWER LLC

STATEMENTS OF MEMBER’S EQUITY

					Member			Accumulated			Total
	Member				Contributions/			Net Income			Member’s
	Units		Amount		Distributions			(Loss)			Equity
	(In thousands of dollars)
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
Contribution from member		—		—		36,843			—			36,843
Net income		—		—		—			10,087			10,087
Balances at December 31, 2004 (Reorganized Company)		1,000	$	1	$	433,134		$	8,525		$	441,660

The accompanying notes are an integral part of these financial statements.

8

INDIAN RIVER POWER LLC

STATEMENTS OF CASH FLOWS

	Reorganized Company						Predecessor Company
				For the			For the
				Period from			Period from
	For the Year			December 6,			January 1,			For the Year
	Ended			2003 to			2003 to			Ended
	December 31,			December 31			December 5,			December 31,
	2004			2003			2003			2002
	(In thousands of dollars)
Cash flows from operating activities
Net income (loss)	$	10,087		$	(1,562	)	$	3,928		$	52,900
Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities Depreciation		17,538			1,080			22,972			23,097
Amortization of intangibles		2,913			—			—			—
Amortization of debt issuance costs		—			—			1,243			1,815
Amortization of out-of-market contracts		—			—			—			(89,251	)
Loss on disposal of assets		1,243			—			—			—
Deferred income taxes		6,972			(1,078	)		2,712			34,926
Changes in assets and liabilities Accounts receivable		(1,160	)		—			10,550			(1,977	)
Accounts receivable — affiliates		(6,330	)		3,736			(3,736	)		—
Inventory		(2,618	)		(2,302	)		7,099			3,082
Prepayments and other current assets		(339	)		193			7,519			(7,965	)
Other assets		(70	)		(5	)		(6,663	)		—
Accounts payable — trade		1			—			3			—
Accounts payable — affiliates		(59,734	)		59,734			(14,901	)		(873	)
Accrued interest		—			(2,497	)		2,457			(1,966	)
Changes in other assets and liabilities		3,511			70			(1,222	)		(6,771	)
Net cash (used in) provided by operating activities		(27,986	)		57,369			31,961			7,017
Cash flows from investing activities
Capital expenditures		(8,857	)		(1,101	)		(11,955	)		(4,917	)
Net cash used in investing activities		(8,857	)		(1,101	)		(11,955	)		(4,917	)
Cash flows from financing activities
Bank overdraft		—			—			(1,028	)		1,028
Payments on debt		—			(310,986	)		(2,007	)		(4,350	)
Contribution from member		36,843			254,718			—			1,222
Distribution to member		—			—			(16,971	)		—
Net cash provided by (used in) financing activities		36,843			(56,268	)		(20,006	)		(2,100	)
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

The accompanying notes are an integral part of these financial statements.

9

INDIAN RIVER POWER LLC

NOTES TO FINANCIAL STATEMENTS

1. Organization

     Indian River Power LLC, or the Company, is an indirect wholly owned subsidiary of NRG Energy, Inc., or NRG Energy. NRG Mid Atlantic Generating LLC, or Mid Atlantic Gen, owns 100% of the Company. Mid Atlantic Gen is a wholly owned subsidiary of NRG Energy.

     From May 14 to December 23, 2003, NRG Energy and a number of its subsidiaries, excluding Mid Atlantic Gen, undertook a comprehensive reorganization and restructuring under chapter 11 of the United States Bankruptcy Code.

2. Summary of Significant Accounting Policies

   Basis of Presentation

     For financial reporting purposes, close of business on December 5, 2003, represents the date of NRG Energy’s emergence from bankruptcy. 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 NRG Energy’s emergence from bankruptcy
	The Company’s operations prior to December 6, 2003
“Reorganized Company”	The Company, after NRG Energy’s emergence from bankruptcy
	The Company’s operations, December 6, 2003 — December 31, 2004

   NRG Energy Fresh Start Reporting/Push Down Accounting

     In accordance with SOP 90-7, 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 immediately before confirmation receive less than 50 percent of the voting shares of the emerging entity. NRG Energy met these requirements and adopted Fresh Start reporting resulting in the creation of a new reporting entity designated as Reorganized NRG. 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.

     The bankruptcy court issued a confirmation order approving 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. The Xcel Energy settlement agreement was entered into on December 5, 2003. NRG Energy 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.

     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, or SFAS No. 109, “Accounting for Income Taxes". The net effect of all Fresh Start adjustments resulted in a gain of $3.9 billion (comprised of a $4.1 billion gain from continuing operations and a $0.2 billion loss from discontinued operations), 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 and push down accounting 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 NRG Energy’s core assets. Management’s forecast incorporated forward commodity market prices obtained from a third party consulting

10

INDIAN RIVER POWER LLC

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 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. 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.

     Due to the adoption of Fresh Start upon NRG Energy’s emergence from bankruptcy and the impact of push down accounting, the Reorganized Company’s 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.

   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. On December 5, 2003, the Company 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 calculated using the straight-line method over the following 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.

Facilities and equipment 4 to 35 years

   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.

   Intangible Assets

     Intangible assets represent contractual rights held by the Company. Intangible assets are amortized over their economic useful life and reviewed for impairment whenever events or change in circumstances indicate carrying values may not be recoverable.

     Intangible assets consist of the fair value of emission allowances. Emission allowance related amounts are amortized as additional fuel expense based upon the actual level of emissions from the respective plant through 2023. Intangible assets are reviewed for impairment on a periodic basis.

11

INDIAN RIVER POWER LLC

   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.

   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 federal and state income taxes has been reflected in the accompanying financial statements (see Note 13 — 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 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 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. Electric energy revenue is recognized upon transmission to the customer. 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, or 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.

   Power Marketing Activities

     The Company has entered into an 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. See Note 10 — Related Party Transactions.

   Credit Risk

     Credit risk relates to the risk of loss resulting from non-performance or non-payment by counter-parties pursuant to the terms of their contractual obligations. NRG Energy monitors and manages its credit risk through credit policies which include an (i) established credit approval process, (ii) daily monitoring of counter-party credit limits, (iii) the use of credit mitigation measures such as margin, collateral, credit derivatives or prepayment arrangements, (iv) the use of payment netting agreements and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counter-party. Risk surrounding counter-party performance and credit could ultimately impact the amount and timing of expected cash flows. NRG Energy has credit protection within various agreements to call on additional collateral support if necessary.

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

12

INDIAN RIVER POWER LLC

   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, disclosure of contingent 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.

   Recent Accounting Pronouncements

     In November 2004, the FASB issued SFAS No. 151, “Inventory Costs- an amendment of ARB No. 43, Chapter 4”. This statement amends the guidance in Accounting Research Bulletin No. 43, Chapter 4, “Inventory Pricing”, and requires that idle facility expense, excessive spoilage, double freight, and rehandling costs be recognized as current-period charges regardless of whether they meet the criteria of “so abnormal” established by Accounting Research Bulletin No. 43. SFAS No.151 is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The Company is currently in the process of evaluating the potential impact that the adoption of this statement will have on the Company’s financial position and results of operations.

     In December 2004, the FASB issued two FASB Staff Positions, or FSPs, regarding the accounting implications of the American Jobs Creation Act of 2004 related to (1) the deduction for qualified domestic production activities (FSP FAS 109-1) and (2) the one-time tax benefit for the repatriation of foreign earnings (FSP FAS 109-2). In FSP FAS 109-1, “Application of FASB Statement No. 109, “Accounting for Income Taxes,” to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004”, the Board decided that the deduction for qualified domestic production activities should be accounted for as a special deduction under FASB Statement No. 109, “Accounting for Income Taxes” and rejected an alternative view to treat it as a rate reduction. Accordingly, any benefit from the deduction should be reported in the period in which the deduction is claimed on the tax return. FSP FAS 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004”, addresses the appropriate point at which a company should reflect in its financial statements the effects of the one-time tax benefit on the repatriation of foreign earnings. Because of the proximity of the Act’s enactment date to many companies’ year-ends, its temporary nature, and the fact that numerous provisions of the Act are sufficiently complex and ambiguous, the Board decided that absent additional clarifying regulations, companies may not be in a position to assess the impact of the Act on their plans for repatriation or reinvestment of foreign earnings. Therefore, the Board provided companies with a practical exception to FAS 109’s requirements by providing them additional time to determine the amount of earnings, if any, that they intend to repatriate under the Act’s beneficial provisions. The Board confirmed, however, that upon deciding that some amount of earnings will be repatriated, a company must record in that period the associated tax liability, thereby making it clear that a company cannot avoid recognizing a tax liability when it has decided that some portion of its foreign earnings will be repatriated. The Company is currently in the process of evaluating the potential impact that the adoption of FSP FAS 109-1 will have on our consolidated financial position and results of operations. The Company does not believe that the potential adoption of FSP 109-2 will have a material impact on our consolidated financial position and results of operation.

     In March 2005, the Financial Accounting Standards Board (FASB) issued Interpretation No. 47 (FIN 47) to Financial Accounting Standard No. 143 (SFAS No. 143) governing the application of Asset Retirement Obligations. FIN 47 clarifies that the term “conditional asset retirement obligation” as used in SFAS 143. SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional but there may remain some uncertainty as to the timing and/or method of settlement. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred — generally upon acquisition, construction, or development and/or through the normal operation of the asset. SFAS No. 143 acknowledges that in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation. FIN 47 clarifies when the company would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective for fiscal years ending after December 15, 2005 and we are currently evaluating the impact of this guidance.

3. Emergence from Bankruptcy and Fresh Start Reporting

     In accordance with the requirements of SFAS No. 141 “Business Combinations”, and push down accounting, the Company’s fair value of $141.6 million, as of Fresh Start date, 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 Fresh Start reporting as of December 5, 2003, the Reorganized Company’s 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 Fresh Start.

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INDIAN RIVER POWER LLC

     The effects of the push down accounting adjustments on the Company’s condensed 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)
Current Assets	$	18,475	$	(1,975	)	$	16,500
Non-current Assets		663,890		(204,696	)		459,194
Total Assets	$	682,365	$	(206,671	)	$	475,694
Current Liabilities	$	313,622	$	44		$	313,666
Non-current Liabilities		103,706		(83,252	)		20,454
		417,328		(83,208	)		334,120
Member’s Equity		265,037		(123,463	)		141,574
Total Liabilities and Member’s Equity	$	682,365	$	(206,671	)	$	475,694

4. Inventory

     Inventory, which is valued at the lower of weighted average cost or market, consists of:

	Reorganized Company
	December 31,		December 31,
	2004		2003
	(In thousands of dollars)
Fuel oil	$	321	$	378
Spare parts		3,774		3,557
Coal		12,225		9,767
Total inventory	$	16,320	$	13,702

5. Property, Plant and Equipment

     The major classes of property, plant and equipment were as follows:

	Average
	Remaining	Reorganized Company
	Useful	December 31,			December 31,			Depreciable
	Life	2004			2003			Lives
	(In thousands of dollars)
Facilities and equipment	21 years	$	397,254		$	380,330		4-35 years
Land and improvements			5,696			5,696
Construction in progress			685			10,075
Total property, plant and equipment			403,635			396,101
Accumulated depreciation			(18,538	)		(1,080	)
Property, plant and equipment, net		$	385,097		$	395,021

6. Asset Retirement Obligations

     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 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 accretion of the asset retirement obligation for the period from January 1, 2003 to December 5, 2003, the period from December 6, 2003 to December 31, 2003 and the year ended December 31, 2004. As a result of adopting Fresh Start, 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 fresh start reporting as of December 5, 2003, equal to 500 to 600 basis points.

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INDIAN RIVER POWER LLC

	Reorganized Company
			Accretion
			for Period				Accretion
	Beginning		December 6,		Ending		for the Year		Ending
	Balance		2003 to		Balance		Ended		Balance
	December 6,		December 31,		December 31,		December 31,		December 31,
	2003		2003		2003		2004		2004
	(In thousands of dollars)
Landfill closure obligation	$	4,198	$	24	$	4,222	$	294	$	4,516

	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

7. Intangible Assets

     Upon the adoption of Fresh Start and application of push down accounting, the Company established intangible assets for plant emissions allowances. These intangible assets are amortized over their lives based on a units of production basis. Emission allowances are amortized as additional fuel expense based upon the actual level of emissions from the plant facilities through 2023. Aggregate amortization expense for the year ended December 31, 2004 and period from December 6, 2003 through December 31, 2003 was approximately $2.9 million and $0 million, respectively. The annual amortization expense for each of the five succeeding years is expected to approximate $2.3 million in 2005 and 2006, $2.4 million in years three and four and $2.3 million in year five. Intangible assets were also reduced by $3.3 million related to a true-up of certain tax evaluations.

     Intangible assets consisted of the following:

	Emission Allowances
	(In Thousands of Dollars)
Balance at December 31, 2003	$	57,531
Amortization		(2,913	)
Other adjustments		(3,293	)
Balance at December 31, 2004	$	51,325

Predecessor Company

     The Company had no intangible assets prior to December 5, 2003.

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INDIAN RIVER POWER LLC

8. Out of Market Contracts

     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 $144.4 million associated with out-of-market contracts. 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 agreements. The long-term agreement required the Company to deliver 500 MW of electrical energy around the clock at a specified price through 2005. The out-of-market contract liability was amortized into revenue based on the terms of the power purchase agreements. Accordingly, the Company recognized $89.3 million in revenues associated with the amortization of the long-term and short-term power purchase agreements during the year ended December 31, 2002.

     On November 8, 2002, Conectiv provided NRG Energy with a Notice of Termination of Transaction under the Master Power Purchase and Sale Agreement, or 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.

9. Sales to Significant Customers

     The Company derives revenues from four significant customers:

	Reorganized Company						Predecessor Company
				For the			For the
				Period			Period
	For the Year			December 6,			January 1,			For the Year
	Ended			2003 to			2003 to			Ended
	December 31,			December 31,			December 5,			December 31,
	2004			2003			2003			2002
				(Percent of total revenues)
Sales to:
Atlantic City Electric, dba Conectiv		38.0	%		45.0	%		78.0	%		95.0	%
Jersey Central Power & Light		17.0	%		—	%		—	%		—	%
Rockland Electric		15.0	%		16.0	%		—	%		—	%
PJM Interconnection		14.0	%		39.0	%		13.0	%		—	%

10. Related Party Transactions

     On June 22, 2001, the Company entered into energy marketing services agreements with NRG Power Marketing Inc., or NRG Power Marketing, a wholly owned subsidiary of NRG Energy. The agreements are effective for consecutive one-year terms until terminated by either party upon 90 days written notice before the end of any such term. Under the agreement, NRG Power Marketing and its wholly owned subsidiary, NJ Energy Sales, will (i) have the exclusive right to manage, purchase 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 costs, taxes, employee labor, contract services, etc.). The Company incurred no fees related to this energy marketing services agreement 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., or 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, the NRG Operating Services company operator operates and maintains the Company’s facility, including (i) coordinating fuel delivery, unloading and inventory, (ii) managing facility spare parts, (iii)

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INDIAN RIVER POWER LLC

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 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 Company 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. These costs are reflected in operating costs in the statements of operations.

     For the year ended December 31, 2004, 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, the Company incurred operating costs billed from NRG Operating Services totaling $44.5 million, $2.9 million, $43.0 million and $43.0 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. For the year ended December 31, 2004, 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, the Company incurred expenses of $5.5 million, $0.7 million, $0.2 million and $0.1 million, respectively. The amounts paid for the year ended December 31, 2004 reflect an overall increase in corporate level general and administrative expenses. Corporate general, administrative and development expenses increase in 2004 due to higher legal fees, increased audit costs and increased consulting costs due to NRG Energy’s Sarbanes-Oxley implementation. The method of allocating these costs remained the same from the prior years.

     At December 31, 2004, the Company had an accounts receivable — affiliates balance of $6.3 million. At December 31, 2003, the Company had an accounts payable — affiliate balance of $59.7 million. These balances are settled on a periodic basis and are due to or due from multiple entities which are wholly owned subsidiaries of NRG Energy Inc. Indian River is an indirect wholly owned subsidiary of NRG Energy Inc., the parent company of Mid Atlantic Generating LLC. Mid Atlantic Generating LLC is the parent company of Indian River Power LLC.

11. Commitments and Contingencies

   Environmental Matters

     Significant amounts of ash are disposed at landfills owned and operated by the Company. The Company maintains financial assurance to cover costs associated with closure, post-closure care and monitoring activities. In accordance with certain regulations established by the Delaware Department of Natural Resources and Environmental Control, the Company has funded a trust in the amount of $6.7 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 $25.0 million during the years 2005 through 2010 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 FASB Interpretation No. 45, or FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others". In connection with push down accounting, all outstanding guarantees were considered new; accordingly, the Company applied the provisions of FIN 45 to all of the guarantees.

     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 certain of NRG Energy’s current and future restricted subsidiaries (other than certain excluded project subsidiaries, foreign subsidiaries and certain other 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

17

INDIAN RIVER POWER LLC

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.

     On December 24, 2004, NRG Energy’s credit facility was amended and restated, or the Amended Credit Facility, whereby NRG Energy repaid outstanding amounts and issued a $450.0 million, seven-year senior secured term loan facility, a $350.0 million funded letter of credit facility, and a three-year revolving credit facility in an amount up to $150.0 million. The Amended 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 NRG Energy and certain of NRG’s current and future subsidiaries, including the Company.

     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	$	1,725,000	Obligations under credit agreement		2013	Nonperformance
NRG Energy Amended and Restated Credit Agreement	$	800,000	Obligations under credit agreement		2011	Nonperformance

     On February 4, 2005, NRG Energy redeemed and retired $375.0 million of Second Priority Notes. As a result of the retirement, the joint and several payment and performance guarantee obligation of the Company was reduced from $1,725.0 million to $1,350.0 million.

12. Regulatory Issues

     On January 25, 2005, FERC issued an order approving the Pennsylvania, Jersey, Maryland Interconnection, or PJM, proposal to increase the compensation for generators which are located in load pockets and are mitigated at least 80% of their running time. Specifically, when the generators would be subject to mitigation, the generator would have the option of recovering their variable costs plus $40 or a negotiated rate with PJM, based on the facility’s going forward costs. If the generator declines both options, it could file for an alternative rate with FERC. Some of the Company’s facilities located in PJM are impacted by the change. The revisions to the cost capping rule could impact the revenues earned by several of the Company’s facilities. In the order, FERC also substantially revised the exemption facilities built after 1996 had from the capping mitigation rule. Under the order the exemption for facilities located in original PJM territory now applies only if the facility was constructed after April 1, 1999. If construction of the facility began after September 30 2003, the exemption would not apply. This limitation to the post 1996 exemption will probably reduce the energy clearing price, or ECP, because units will be subject to the cost capping rule and therefore will be unable to set the ECP.

13. Income Taxes

     The Company is included in the consolidated income tax return filings of NRG Energy. Reflected in the financial statements and notes below are federal and state income tax provisions, as if the Company had prepared separate filings. The Company’s ultimate parent, NRG Energy, does not have a tax allocation agreement with its subsidiaries. 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.

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INDIAN RIVER POWER LLC

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

	Reorganized Company						Predecessor Company
				For the			For the
				Period from			Period from
	For the Year			December 6,			January 1,			For the Year
	Ended			2003 to			2003 to			Ended
	December 31,			December 31,			December 5,			December 31,
	2004			2003			2003			2002
	(In thousands of dollars)
Current
Federal	$	—		$	—		$	—		$	—
State		—			—			—			—
		—			—			—			—
Deferred
Federal		5,436			(841	)		2,115			27,231
State		1,536			(237	)		597			7,695
		6,972			(1,078	)		2,712			34,926
Total income tax expense (benefit)	$	6,972		$	(1,078	)	$	2,712		$	34,926
Effective tax rate		40.9	%		40.8	%		40.8	%		39.8	%

     The pre-tax net income (loss) was as follows:

	Reorganized Company					Predecessor Company
			For the			For the
			Period from			Period from
	For the Year		December 6,			January 1,		For the Year
	Ended		2003 to			2003 to		Ended
	December 31,		December 31,			December 5,		December 31,
	2004		2003			2003		2002
	(In thousands of dollars)
U.S	$	17,059	$	(2,640	)	$	6,640	$	87,826

     The components of the net deferred income tax liability were:

	Reorganized Company
	December 31,		December 31,
	2004		2003
	(In thousands of dollars)
Deferred tax liabilities
Property	$	26,736	$	—
Emissions credits		18,752		23,501
Other		774		562
Total deferred tax liabilities		46,262		24,063
Deferred tax assets
Difference between book and tax basis of contracts		1,539		—
Property		—		5,985
Asset retirement obligation		1,845		1,725
Domestic tax loss carryforwards		20,281		733
Other		437		432
Total deferred tax assets		24,102		8,875
Net deferred tax liability	$	22,160	$	15,188

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INDIAN RIVER POWER LLC

     The net deferred tax liability consists of:

	Reorganized Company
	December 31,		December 31,
	2004		2003
	(In thousands of dollars)
Current deferred tax liability	$	—	$	44
Noncurrent deferred tax liability		22,160		15,144
Net deferred tax liability	$	22,160	$	15,188

     In assessing the realizabilty of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The realization of deferred tax assets is dependent upon the generation of taxable income in future periods. Management considers both positive and negative evidence, projected operating income and capital gains, and available tax planning strategies in making this assessment. Based upon projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Company will realize the benefits of these net deferred tax assets as of December 31, 2004. There is a net carryforward amount of $49.6 million available at December 31, 2004 which will expire by 2023 if unutilized.

     In connection with the Company’s emergence from bankruptcy, the 2003 net operating loss carryforward was effectively increased as a result of the Company’s election in 2004 to reduce the tax basis of property on a going forward basis. This election was made in 2004 in connection with tax planning strategies for future periods and accordingly was recorded subsequent to the period ended December 31, 2003.

     In 2004, the Company utilized $41.3 million of U.S. net operating losses carryforward of $90.9 million. There is a net carryforward amount of $49.6 million available at December 31, 2004, which will expire by 2023 if unutilized.

     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
	For the Year					December 6,					January 1,					For the Year
	Ended					2003 to					2003 to					Ended
	December 31,					December 31,					December 5,					December 31,
	2004					2003					2003					2002
	(In thousands of dollars)
Income (loss) before taxes	$	17,059				$	(2,640	)			$	6,640				$	87,826
Tax at 35%		5,970		35.0	%		(924	)	35.0	%		2,324		35.0	%		30,739		35.0	%
State taxes (net of federal benefit)		1,037		5.9	%		(155	)	5.8	%		389		5.8	%		5,002		5.7	%
Other		(35	)	—	%		1		—	%		(1	)	—	%		(815	)	(0.9	)%
Income tax (benefit) expense	$	6,972		40.9	%	$	(1,078	)	40.8	%	$	2,712		40.8	%	$	34,926		39.8	%

     Income tax expense for all periods reflect the federal and state tax and there are no special tax credits.

14. Long-Term Debt

     On June 22, 2001, the Company’s parent 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. The parent loaned the proceeds from the debt to its subsidiaries. The amount loaned by the parent to the Company was $317.3 million. On December 23, 2003, NRG Energy issued $1.25 billion in Second Priority Notes, due and payable on December 15, 2003. 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 its parent and payables to affiliates to pay the outstanding principal of $311 million and accrued interest of $2.5 million.

     The debt 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 year ended December 31, 2002, the weighted average interest rate was 3.30%.

20

EX-99.6

EXHIBIT 99.6

OSWEGO HARBOR POWER LLC

FINANCIAL STATEMENTS

At December 31, 2004 and 2003,
and for the Year Ended December 31, 2004,
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

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OSWEGO HARBOR POWER LLC

INDEX

	Page
Reports of Independent Registered Public Accounting Firm	3
Balance Sheets at December 31, 2004 and 2003	5
Statements of Operations for the year ended December 31, 2004, 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	6
Statements of Member’s Equity and Comprehensive Income for the year ended December 31, 2004, 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	7
Statements of Cash Flows for the year ended December 31, 2004, 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	8
Notes to Financial Statements	9

2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Member of
Oswego Harbor Power LLC

     We have audited the accompanying balance sheets of Oswego Harbor Power LLC (“Reorganized Company”) as of December 31, 2004 and 2003, and the related statements of operations, member’s equity (deficit) and comprehensive income, and cash flows for the year ended December 31, 2004 and the period from December 6, 2003 to December 31, 2003. 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 in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

     In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Oswego Harbor Power LLC as of December 31, 2004 and 2003, and the results of its operations and its cash flows for the year ended December 31, 2004 and the period from December 6, 2003 to December 31, 2003, in conformity with U.S. generally accepted accounting principles.

     As discussed in Notes 1 and 2 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/	KPMG LLP
	KPMG LLP

Philadelphia, Pennsylvania
May 27, 2005

3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Member of
Oswego Harbor Power LLC

     We have audited the accompanying statements of operations, member’s equity/(deficit) and comprehensive income, and cash flows of Oswego Harbor Power LLC (“Predecessor Company”) for the period from January 1, 2003 to December 5, 2003 and for the year ended December 31, 2002. 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 in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

     In our opinion, the financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of Oswego Harbor Power LLC for the period from January 1, 2003 to December 5, 2003 and for the year ended December 31, 2002, in conformity with U.S. generally accepted accounting principles.

     As discussed in Notes 1 and 2 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/	KPMG LLP
	KPMG LLP

Philadelphia, Pennsylvania
May 27, 2005

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OSWEGO HARBOR POWER LLC

BALANCE SHEETS

	Reorganized Company
	December 31,		December 31,
	2004		2003
	(In thousands of dollars)
ASSETS
Current assets
Restricted cash	$	1,414	$	1,406
Accounts receivable — affiliates		3,155		1,756
Inventory		67,396		39,735
Derivative instruments valuation		2,383		—
Prepayments and other current assets		1,675		1,272
Total current assets		76,023		44,169
Property, plant and equipment, net of accumulated depreciation of $11,678 and $897, respectively		243,888		251,103
Intangible assets, net of accumulated amortization of $2,535 and $0, respectively		34,897		36,694
Total assets	$	354,808	$	331,966
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	1,666	$	—
Notes payable – affiliate		—		2,493
Other accrued liabilities		—		102
Current deferred income taxes		—		28
Accrued station service costs		10,510		7,570
Other current liabilities		1,139		1,004
Total current liabilities		13,315		11,197
Other long-term obligations		287		—
Deferred income taxes		91,073		94,006
Total liabilities		104,675		105,203
Commitments and contingencies
Member’s equity		250,133		226,763
Total liabilities and member’s equity	$	354,808	$	331,966

The accompanying notes are an integral part of these financial statements.

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OSWEGO HARBOR POWER LLC

STATEMENTS OF OPERATIONS

	Reorganized Company						Predecessor Company
				For the			For the
				Period from			Period from
	For the Year			December 6,			January 1,			For the Year
	Ended			2003 to			2003 to			Ended
	December 31,			December 31,			December 5,			December 31,
	2004			2003			2003			2002
	(In thousands of dollars)
Revenues	$	54,029		$	2,800		$	63,284		$	71,126
Operating costs		31,921			1,708			35,870			43,786
Depreciation		10,781			897			2,473			2,686
General and administrative expenses		7,243			632			4,853			2,755
Reorganization charges		—			—			1,410			—
Income (loss) from operations		4,084			(437	)		18,678			21,899
Other income (expense), net		8			1			(28	)		(54	)
Interest expense		(173	)		(175	)		(3,837	)		(4,306	)
Income (loss) before income taxes		3,919			(611	)		14,813			17,539
Income tax expense (benefit)		1,505			(184	)		5,906			6,994
Net income (loss)	$	2,414		$	(427	)	$	8,907		$	10,545

The accompanying notes are an integral part of these financial statements.

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OSWEGO HARBOR POWER LLC

STATEMENTS OF MEMBER’S EQUITY /(DEFICIT) AND COMPREHENSIVE INCOME

											Accumulated		Total
					Member’s			Accumulated			Other		Member’s
	Member’s				Contributions/			Net Income			Comprehensive		Equity
	Units		Amount		Distributions			(Loss)			Income		(Deficit)
	(In thousands of dollars)
Balances at December 31, 2001 (Predecessor Company)		1,000	$	1	$	(70,541	)	$	44,267			—	$	(26,273	)
Net income		—		—		—			10,545			—		10,545
Contribution from member		—		—		6,638			—			—		6,638
Balances at December 31, 2002 (Predecessor Company)		1,000	$	1	$	(63,903	)	$	54,812		$	—	$	(9,090	)
Net income		—		—		—			8,907			—		8,907
Contribution from member		—		—		5,241			—			—		5,241
Distribution to member		—		—		(35,510	)		—			—		(35,510	)
Balances at December 5, 2003 (Predecessor Company)		1,000	$	1	$	(94,172	)	$	63,719		$	—	$	(30,452	)
Push down accounting adjustments		—		—		274,184			(63,719	)		—		210,465
Balances at December 6, 2003 (Reorganized Company)		1,000	$	1	$	180,012		$	—		$	—	$	180,013
Contribution from member		—		—		47,177			—			—		47,177
Net Loss		—		—		—			(427	)		—		(427	)
Balances at December 31, 2003 (Reorganized Company)		1,000	$	1	$	227,189		$	(427	)	$	—	$	226,763
Impact of SFAS No. 133 for the year ending December 31, 2004, net of income tax of $943		—		—		—			—			1,440		1,440
Net income		—		—		—			2,414			—		2,414
Comprehensive income		—		—		—			—			—		3,854
Contribution from member		—		—		23,605			—			—		23,605
Distribution to member		—		—		(4,089	)		—			—		(4,089	)
Balances at December 31, 2004 (Reorganized Company)		1,000	$	1	$	246,705		$	1,987		$	1,440	$	250,133

The accompanying notes are an integral part of these financial statements.

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OSWEGO HARBOR POWER LLC

STATEMENTS OF CASH FLOWS

	Reorganized Company						Predecessor Company
				For the			For the
				Period from			Period from
	For the Year			December 6,			January 1,			For the Year
	Ended			2003 to			2003 to			Ended
	December 31,			December 31,			December 5,			December 31,
	2004			2003			2003			2002
	(In thousands of dollars)
Cash flows from operating activities
Net income (loss)	$	2,414		$	(427	)	$	8,907		$	10,545
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation		10,781			897			2,473			2,686
Amortization of deferred finance charges		—			—			32			33
Amortization of intangible assets		2,535			—			—			—
Deferred income taxes		(3,904	)		(356	)		665			611
Current tax expense — noncash contribution from member		5,409			172			5,241			6,383
Debt issuance write-off		—			—			716			—
Changes in assets and liabilities
Accounts receivable		—			—			3,385			(301	)
Accounts receivable/payable — affiliates		3,183			823			25,574			(34,177	)
Inventory		(27,661	)		1			(13,637	)		18,336
Prepayments and other current assets		(403	)		446			(650	)		(76	)
Accounts payable		1,666			—			—			—
Accrued interest		—			(2,056	)		1,840			(91	)
Accrued station service costs and other accrued liabilities		2,973			(286	)		2,509			(1,744	)
Changes in other liabilities		287			—			—			—
Net cash provided by (used in) operating activities		(2,720	)		(786	)		37,055			2,205
Cash flows from investing activities
Increase in restricted cash		(8	)		—			(1,406	)		—
Capital expenditures		(3,566	)		—			(140	)		(506	)
Net cash used in investing activities		(3,574	)		—			(1,546	)		(506	)
Cash flows from financing activities
Principal payments on notes payable-affiliate		(2,493	)		(46,219	)		—			(1,953	)
Contribution from member		12,876			47,005			—			—
Distribution to member		(4,089	)		—			(35,510	)		255
Net cash (used in) provided by financing activities		6,294			786			(35,510	)		(1,698	)
Net change in cash and cash equivalents		—			—			(1	)		1
Cash and cash equivalents
Beginning of period		—			—			1			—
End of period	$	—		$	—		$	—		$	1
Supplemental disclosures of cash flow information
Cash paid for interest	$	166		$	80		$	4		$	4,299
Non-cash equity contribution	$	5,320		$	—		$	—		$	—

The accompanying notes are an integral part of these financial statements.

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OSWEGO HARBOR POWER LLC

NOTES TO FINANCIAL STATEMENTS

1. Organization

     Oswego Harbor Power LLC, or the Company is an indirect wholly owned subsidiary of NRG Energy, Inc., or NRG Energy. NRG Northeast Generating LLC, or NRG Northeast owns 100% of the Company. NRG Northeast is a wholly owned subsidiary of NRG Energy.

     In 2002, a number of factors, most notably the aggressive prices paid by NRG Energy for acquisitions of turbines, development projects and plants, combined with the overall downturn in the power generation industry, triggered a series of credit rating downgrades which, in turn, precipitated a severe liquidity crisis at NRG Energy. From May 14, 2003 to December 23, 2003, NRG Energy and a number of subsidiaries, including the Company, undertook a comprehensive reorganization and restructuring under chapter 11 of the United States Bankruptcy Code. The Northeast/South Central Plan of Reorganization, relating to the Company and the NRG South Central LLC subsidiaries 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.

     The creditors of Northeast and South Central subsidiaries were not impaired 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 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

Basis of Presentation

     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 Statement of Position 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code”, or SOP 90-7.

     For financial reporting purposes, close of business on December 5, 2003, represents the date of the Company’s emergence from bankruptcy because that is the date of emergence for the ultimate parent company, NRG Energy. As previously stated, the Company emerged from bankruptcy on December 23, 2003. The accompanying financial statements reflect the impact of the Company’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, pre-emergence from bankruptcy
	The Company’s operations prior to December 6, 2003
“Reorganized Company”	The Company, post-emergence from bankruptcy
	The Company’s operations, December 6, 2003 — December 31, 2004

Fresh Start Reporting/Push Down Accounting

     In accordance with SOP 90-7, 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 immediately before confirmation receive less than 50 percent of the voting shares of the emerging entity. NRG Energy met these requirements and adopted Fresh Start reporting resulting in the creation of a new reporting entity designated as Reorganized NRG. 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.

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OSWEGO HARBOR POWER LLC

     The bankruptcy court issued a confirmation order approving 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. The Xcel Energy settlement agreement was entered into on December 5, 2003. NRG Energy 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.

     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 (comprised of a $4.1 billion gain from continuing operations and a $0.2 billion loss from discontinued operations), 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 and push down accounting 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 NRG Energy’s 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 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. 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.

     A separate plan of reorganization was filed for NRG Northeast 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, NRG Energy accounted for these entities as if they had emerged from bankruptcy at the same time that NRG Energy emerged, as it is believed that NRG Energy continued to maintain control over the Company facilities throughout the bankruptcy process.

     Due to the adoption of Fresh Start upon NRG Energy’s emergence from bankruptcy and the impact of push down accounting, the Reorganized Company’s 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.

   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.

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OSWEGO HARBOR POWER LLC

   Restricted Cash

     Restricted cash consists primarily of funds held to satisfy the requirements of certain debt agreements and funds held within the Company’s projects that are restricted in their use. These funds are used to pay current operating expenses and current debt service payments, per the restrictions of the debt agreements.

   Inventory

     Inventory is valued at the lower of weighted average cost or market and consists principally of fuel oil and spare parts.

   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, the Company 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. The assets and related accumulated depreciation amounts are adjusted for asset retirements and disposals with the resulting gain or loss included in operations.

Facilities and equipment	2 to 25 years
Office furnishings and equipment	2 to 10 years

   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 Statement of Financial Accounting Standards or 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.

   Intangible Assets

     Intangible assets consist primarily of the fair value of emission allowances. Emission allowance related amounts are amortized as additional fuel expense based upon the actual level of emissions from the 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. Electric energy revenue is recognized upon transmission to the customer.

     In certain markets, which are operated/controlled by an independent system operator, or ISO, and in which the Company has entered into a netting agreement with the 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 has entered into an agreement with a marketing affiliate for the sale of energy, capacity and ancillary services produced, and for the procurement and management of fuel (oil derivatives and natural gas) and emission credit allowances, which enables the affiliate to engage in forward sales and hedging transactions to manage the Company’s electricity and fuel price exposure. See Note 11 – Related Party Transactions.

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OSWEGO HARBOR POWER LLC

   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 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 member in the statement of member’s equity and 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 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.

   Credit Risk

     Credit risk relates to the risk of loss resulting from non-performance or non-payment by counter-parties pursuant to the terms of their contractual obligations. NRG Energy monitors and manages the credit risk of its affiliates including the Company, through credit policies which include (i) an established credit approval process, (ii) daily monitoring of counter-party credit limits, (iii) the use of credit mitigation measures such as margin, collateral, credit derivatives or prepayment arrangements, (iv) the use of payment netting agreements and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counter-party. Risk surrounding counter-party performance and credit could ultimately impact the amount and timing of expected cash flows. NRG Energy has credit protection within various agreements to call on additional collateral support if necessary.

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

   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 note payable – affiliate approximates carrying value as the underlying instrument bears a variable market interest rate.

   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, disclosure of contingent 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.

   Recent Accounting Pronouncements

     In November 2004, the FASB issued SFAS No. 151, “Inventory Costs- an amendment of Accounting Research Bulletin No. 43, Chapter 4”. This statement amends the guidance in ARB No. 43, Chapter 4, “Inventory Pricing”, and requires that idle facility expense, excessive spoilage, double freight, and rehandling costs be recognized as current-period charges regardless of whether they

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OSWEGO HARBOR POWER LLC

meet the criterion of “so abnormal” established by ARB No.43. SFAS No.151 is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The Company is currently in the process of evaluating the potential impact that the adoption of this statement will have on the Company’s financial position and results of operations.

     In December 2004, the FASB issued two FASB Staff Positions, or FSPs, regarding the accounting implications of the American Jobs Creation Act of 2004 related to (1) the deduction for qualified domestic production activities (FSP FAS 109-1) and (2) the one-time tax benefit for the repatriation of foreign earnings (FSP FAS 109-2). In FSP FAS 109-1, “Application of FASB Statement No. 109, “Accounting for Income Taxes,” to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004”, the Board decided that the deduction for qualified domestic production activities should be accounted for as a special deduction under FASB Statement No. 109, “Accounting for Income Taxes” and rejected an alternative view to treat it as a rate reduction. Accordingly, any benefit from the deduction should be reported in the period in which the deduction is claimed on the tax return. FSP FAS 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004”, addresses the appropriate point at which a company should reflect in its financial statements the effects of the one-time tax benefit on the repatriation of foreign earnings. Because of the proximity of the Act’s enactment date to many companies’ year-ends, its temporary nature, and the fact that numerous provisions of the Act are sufficiently complex and ambiguous, the Board decided that absent additional clarifying regulations, companies may not be in a position to assess the impact of the Act on their plans for repatriation or reinvestment of foreign earnings. Therefore, the Board provided companies with a practical exception to FAS 109’s requirements by providing them additional time to determine the amount of earnings, if any, that they intend to repatriate under the Act’s beneficial provisions. The Board confirmed, however, that upon deciding that some amount of earnings will be repatriated, a company must record in that period the associated tax liability, thereby making it clear that a company cannot avoid recognizing a tax liability when it has decided that some portion of its foreign earnings will be repatriated. The Company is currently in the process of evaluating the potential impact that the adoption of FSP FAS 109-1 will have on our financial position and results of operations. The Company does not believe that the potential adoption of FSP 109-2 will have a material impact on our financial position and results of operation.

     In March 2005, the Financial Accounting Standards Board (FASB) issued Interpretation No. 47 (FIN 47) to Financial Accounting Standard No. 143 (SFAS No. 143) governing the application of Asset Retirement Obligations. FIN 47 clarifies that the term “conditional asset retirement obligation” as used in SFAS 143. SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional but there may remain some uncertainty as to the timing and/or method of settlement. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred — generally upon acquisition, construction, or development and/or through the normal operation of the asset. SFAS No. 143 acknowledges that in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation. FIN 47 clarifies when the company would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective for fiscal years ending after December 15, 2005 and we are currently evaluating the impact of this guidance.

3. Emergence from Bankruptcy and Fresh Start Reporting

     In accordance with the requirement of SFAS No. 141 “Business Combinations,” the Company’s fair value of $286.0 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 Fresh Start 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 Fresh Start.

4. Other Charges

     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 $0.7 million to write-off debt related issuance costs as well as incurring a pre-payment charge of approximately $0.7 million for the refinancing transaction completed with the emergence from bankruptcy of the Company. The $0.7 million was expensed in November 2003, as it was determined to be an allowable claim at that time.

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OSWEGO HARBOR POWER LLC

	Reorganized Company
			For the Period		Predecessor Company
			from		For the Period from
	For the Year		December 6,		January 1, 2003		For the Year
	Ended		2003 through		Through		Ended
	December 31,		December 31,		December 5,		December 31,
	2004		2003		2003		2002
	(In thousands of dollars)
Deferred financing write offs	$	—	$	—	$	716	$	—
Pre-payment charge		—		—		694		—
Total reorganization items	$	—	$	—	$	1,410	$	—

5. Inventory

     Inventory, which is valued at the lower of weighted average cost or market, consists of:

	December 31,		December 31,
	2004		2003
	(In thousands of dollars)
Fuel oil	$	63,106	$	35,343
Spare parts		4,290		4,392
Total inventory	$	67,396	$	39,735

6. Property, Plant and Equipment

     The major classes of property, plant and equipment were as follows:

								Average
		Reorganized Company						Remaining
	Depreciable	December 31,			December 31,			Useful
	Lives	2004			2003			Life
	(In thousands of dollars)
Facilities, machinery and equipment	2-25 years	$	241,621		$	241,344		21 years
Land and improvements			10,502			10,502
Construction in progress			3,261			—
Office furnishings and equipment	2-10 years		182			154		2 years
Total property, plant and equipment			255,566			252,000
Accumulated depreciation			(11,678	)		(897	)
Property, plant and equipment, net		$	243,888		$	251,103

7. Asset Retirement Obligations

     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.

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OSWEGO HARBOR POWER LLC

     The Company identified certain retirement obligations related to environmental obligations. 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 Company had no asset retirement obligations prior to 2004. In 2004 an asset retirement obligation of $0.3 million was capitalized. The asset retirement obligation is included in other long-term obligations in the balance sheet.

8. Intangible Assets

   Reorganized Company

     Upon adoption of Fresh Start and application of push down accounting, the Company established certain intangible assets for plant emission allowances. The intangible assets are amortized over their respective lives based upon the actual usage of credits during any reporting period from the respective plants through 2023. Aggregate amortization recognized for the year ended December 31, 2004 was approximately $2.5 million. The annual aggregate amortization for each of the five succeeding years is expected to approximately $1.1 million in 2005, $1.0 million in 2006, $0.8 million in 2007, $1.0 million in 2008 and $0.7 million in 2009. Intangible assets were increased by $0.7 million during the year ended December 31, 2004 consisting of a $2.7 million reduction in connection with the recognition of certain tax credits to be claimed on the Company’s New York State franchise tax return and $3.4 million of adjustments related to a true up of certain tax evaluations.

     Intangible assets consisted of the following:

	Emission Allowances
	(In Thousands of Dollars)
Balance at December 31, 2003	$	36,694
Amortization		(2,535	)
Other adjustments		738
Balance at December 31, 2004	$	34,897

     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. Financial Instruments

     The estimated fair values of the Company’s recorded financial instruments are as follows:

	December 31, 2004				December 31, 2003
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
	(In thousands of dollars)
Restricted cash	$	1,414	$	1,414	$	1,406	$	1,406
Accounts receivable - affiliates		2,704		2,704		1,756		1,756
Accounts payable		1,666		1,666		—		—
Notes payable – affiliate		—		—		2,493		2,493

     For restricted cash, accounts receivable and accounts payable, the carrying amount approximates fair value because of the short-term maturity of those instruments. The fair value of note payable — affiliate approximates carrying value as the underlying instruments bear a variable market interest rate.

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OSWEGO HARBOR POWER LLC

10. Notes Payable – Affiliates

     The Company reflected $2.5 million as their share of NRG Northeast’s balance owed to NRG Energy as of December 31, 2003. The debt was repaid in March 2004. Accordingly, the Company has classified this loan as a short-term affiliated note payable at December 31, 2003.

11. Related Party Transactions

     On June 22, 2001, the Company entered into an energy marketing services agreement with NRG Power Marketing Inc., or NRG Power Marketing, a wholly owned subsidiary of NRG Energy. The agreement is effective for consecutive one-year terms until terminated by either party upon 90 days written notice before the end of any such term. Under the agreement, NRG Power Marketing will (i) have the exclusive right to manage, market, hedge and sell all power not otherwise sold or committed to by the Company, (ii) procure, provide and hedge for all fuel required to operate the facility 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 affect the dispatch of the power output from the facility.

     Under the agreement, 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 costs, taxes, labor, contract services, etc.). The Company incurs no fees related to this agreement with NRG Power Marketing.

     As of December 31, 2004, the Company had no employees and had entered into operation and maintenance agreements with a subsidiary of NRG Operating Services, Inc., or NRG Operating Services, a wholly owned subsidiary of NRG Energy. The agreements were effective for five years, with options to extend beyond five years. Under the agreements, NRG Operating Services operated and maintained the respective facilities, 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 charged an annual fee, and in addition, was reimbursed for usual and customary costs related to providing the services including plant labor and other operating costs. These costs are reflected in operating costs in the statements of operations.

     Effective January 1, 2005, the operations and maintenance agreements were terminated and the Company assumed responsibility for services formerly provided by the subsidiary of NRG Operating Service, Inc.

     For the year ended December 31, 2004, 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, the Company incurred operating costs billed from NRG Operating Services totaling $21.9 million, $1.6 million, $16.0 million and $16.5 million, respectively.

     On June 22, 2001, the Company 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 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 statements of operations.

     For the year ended December 31, 2004, 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, the Company paid NRG Energy approximately $3.0 million, $0.3 million, $0.9 million and $0.2 million, respectively, for corporate support and services. The amounts paid for the year ended December 31, 2004 reflect an overall increase in corporate level general and administrative expenses. Corporate general, administrative and development expenses increase in 2004 due to higher legal fees, increased audit costs and increased consulting costs due to NRG Energy’s Sarbanes-Oxley implementation. The method of allocating these costs remained the same from the prior years.

     At December 31, 2004, the Company had an accounts receivable – affiliate balance of $2.7 million. At December 31, 2003, the Company had accounts receivable –affiliates balance of $1.8 million. These balances are due to and due from multiple entities which

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OSWEGO HARBOR POWER LLC

are wholly owned subsidiaries of NRG Energy Inc, the parent company of Northeast Generating LLC. Northeast Generating LLC is the parent company of Oswego Harbor Power LLC.

12. Sales to Significant Customers

     For the year ended December 31, 2004, the Company derived approximately 94.2% of total revenues from the New York Independent System Operator, or NYISO. For the period from December 6, 2003 to December 31, 2003, the Company derived 100% of total revenues from the NYISO. For the period from January 1, 2003 to December 5, 2003, the Company derived approximately 74.1% of total revenues from the NYISO and 25.5% from Niagara Mohawk Power Corporation. During 2002 the Company derived 61.3% of total revenues from the NYISO and 36.6% from Niagara Mohawk Power Corporation. NYISO is a FERC-regulated independent system operator that manages transmission assets collectively under their control to provide non-discriminatory access to their respective transmission grids. The NYISO exercises operational control over most of New York State’s transmission facilities. We anticipate that NYISO will continue to be a significant customer given the scale of our asset base in the NYISO control area.

13. Accounting for Derivative Instruments and Hedging Activity

     SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” as amended by SFAS No. 137, SFAS No. 138 and SFAS No. 149 requires the Company to recognize all derivative instruments on the balance sheet as either assets or liabilities and measure them at fair value each reporting period. If certain conditions are met, the Company may be able to designate derivatives as cash flow hedges and defer the effective portion of the change in fair value of the derivatives in Accumulated Other Comprehensive Income (OCI) and subsequently recognize in earnings when the hedged items impact income. The ineffective portion of a cash flow hedge is immediately recognized in income.

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

     For derivatives that are neither designated as cash flow hedges or do not qualify for hedge accounting treatment, the changes in the fair value will be immediately recognized in earnings.

     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, 2004, the Company had various commodity contracts extending through December 2005 .

   Energy Related Commodities

     The Company is exposed to commodity price variability in electricity, emission allowances, natural gas, and oil derivatives 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 year ended December 31, 2004, 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, the Company recognized no gain or loss due to ineffectiveness of commodity cash flow hedges.

     The Company’s earnings for the year ended December 31, 2004 were decreased by an unrealized loss of $0.02 million, for the period from December 6, 2003 to December 31, 2003 earnings were increased by unrealized gains of $0.2 million, for the period from January 1, 2003 to December 5, 2003 earning were not impacted, and for the year ended December 31, 2002 earnings were impacted by unrealized gains of $0.8 million associated with changes in the fair value of energy related derivative instruments not accounted for as hedges in accordance with SFAS No. 133.

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OSWEGO HARBOR POWER LLC

   Accumulated Other Comprehensive Income

     The following table summarizes the effects of SFAS No. 133, as amended, on the Company’s other comprehensive income balance attributable to hedged derivatives for the year ended December 31, 2004, 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:

	Reorganized Company					Predecessor Company
				For the		For the
				Period from		Period from
	For the Year			December 6,		January 1,		For the Year
	Ended			2003 to		2003 to		Ended
	December 31,			December 31,		December 5,		December 31,
	2004			2003		2003		2002
	(In thousands of dollars)
Energy Commodities Gains (Losses)
Beginning accumulated OCI balance	$	—		$	—	$	—	$	—
Mark to market of hedge contracts		2,383			—		—		—
Current year tax effect		(943	)		—		—		—
Ending accumulated OCI balance	$	1,440		$	—	$	—	$	—
Gains expected to unwind from OCI during next 12 months	$	1,440

     During the year ended December 31, 2004, the period 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, the Company reclassified no amounts from OCI to current-period earnings. During the year ended December 31, 2004, the Company recorded gains in OCI of approximately $2.4 million related to changes in fair values of derivates accounted for as hedges.

   Statement of Operations

     The following table summarize the pre-tax effects of non-hedge derivatives and derivatives that no longer qualify as hedges on the Company’s statement of operations for the year ended December 31, 2004, 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:

	Reorganized Company					Predecessor Company
				For the		For the
				Period from		Period from
	For the Year			December 6,		January 1,		For the Year
	Ended			2003 to		2003 to		Ended
	December 31,			December 31,		December 5,		December 31,
	2004			2003		2003		2002
	(In thousands of dollars)
Energy Commodities Gains
Operating costs	$	(24	)	$	245	$	—	$	788
Total statement of operations impact before tax	$	(24	)	$	245	$	—	$	788

14. Commitments and Contingencies

   Environmental Regulatory Matters

     The construction and operation of power projects are subject to stringent environmental and safety protection and land use laws and regulations in the U. S. These laws and regulations generally require lengthy and complex processes to obtain permits and approvals from federal, state and local agencies. If such laws and regulations become more stringent, or new laws, interpretations of compliance policies apply and the Company’s facility is 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

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OSWEGO HARBOR POWER LLC

environmental and safety laws for the cleanup of pollutants released at its facility or at off-site locations where it may have sent waste, even if the release or off-site disposal was conducted in compliance with the law.

     The company strives to at least meet 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, future laws and regulations are expected to require the addition of pollution control equipment or the imposition of restrictions on the Company’s operations.

     As part of acquiring existing generating assets, the Company 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.

     In response to liabilities associated with these activities, the Company establishes accruals where it is probable that it will incur environmental costs under applicable law or contracts and it is possible to reasonably estimate these costs. The Company adjusts the accruals when new remediation or other environmental liability responsibilities are discovered and probable costs become estimable, or when current liability estimates are adjusted to reflect new information or a change in the law.

     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 hazardous material releases or threatened releases. These laws impose strict (without fault) and joint and several liability. The cost of investigation, remediation or removal of any hazardous or toxic substances or petroleum products could be substantial. Although the Company has been involved in on-site contamination matters, to date, it has not been named as a potentially responsible party with respect to any off-site waste disposal matter.

     Oswego Harbor Power LLC was one of three NRG Energy facilities issued Notices of Violation for opacity exceedances and all three entered into a Consent Order with the New York State Department of Environmental Conservation, or NYSDEC. The Consent Order required the respondents to pay a collective civil penalty of $1 million which was paid in April 2004. The Order also establishes stipulated penalties (payable quarterly) for future violations of opacity requirements and a compliance schedule. NRG Energy is currently in dispute with NYSDEC over the method of calculation for any such stipulated penalties. NRG Energy has placed $867,400 in a reserve of which the Company has $26,900 as of December 31, 2004, and does not believe that the final resolution of this dispute will involve a material larger amount.

   NYISO Claims

     In November 2002, 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. New York City mitigation adjustments totaled $11.4 million. The issue related to NYISO’s concern that NRG would not have sufficient revenue to cover subsequent revisions to its energy market settlements. As of December 31, 2004, NYISO held $3.9 million in escrow for such future settlement revisions.

   Guarantees

     In November 2002, the Financial Accounting Standards Board, or FASB issued FASB Interpretation, or FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”. In connection with the adoption of Fresh Start, all outstanding guarantees were considered new; accordingly, the Company applied the provisions of FIN 45 to all of the 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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OSWEGO HARBOR POWER LLC

     NRG Energy’s payment obligations under the notes and all related Parity Lien Obligations are guaranteed on an unconditional basis by certain of NRG Energy’s current and future restricted subsidiaries (other than certain excluded project subsidiaries, foreign subsidiaries and certain other 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.

     On December 24, 2004, NRG Energy’s credit facility was amended and restated, or the Amended Credit Facility, whereby NRG Energy repaid outstanding amounts and issued a $450.0 million, seven-year senior secured term loan facility, a $350.0 million funded letter of credit facility, and a three-year revolving credit facility in an amount up to $150.0 million. The Amended 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 NRG Energy and certain of NRG’s current and future subsidiaries, including the Company.

     The Company’s obligations pursuant to its guarantees of the performance, equity and indebtedness obligations were as follows:

	Guarantee/ Maximum			Expiration
Project/Subsidiary	Exposure		Nature of Guarantee	Date	Triggering Event
	(In thousands of dollars)
NRG Energy Second Priority Notes due 2013	$	1,725,000	Obligations under credit agreement	2013	Nonperformance
NRG Energy Amended and Restated Credit Agreement	$	800,000	Obligations under credit agreement	2011	Nonperformance

     On February 4, 2005, NRG Energy redeemed and retired $375.0 million of Second Priority Notes. As a result of the retirement, the joint and several payment and performance guarantee obligation of the Company was reduced from $1,725.0 million to $1,350.0 million.

   Legal Issues

     The Company has been put on notice that the prior owner of Oswego Harbor Power LLC is seeking indemnification and defense in connection with several lawsuits alleging liability for damages to persons allegedly exposed to asbestos-containing materials at the plant. The prior owner alleges that the Company is liable pursuant to the terms of the April 1, 1999 Asset Sales Agreements pursuant to which the Company acquired the plant, which is disputed. To date, the prior owner has not filed suit against the Company with respect to its claim for indemnification with respect to these cases.

Niagara Mohawk Power Corporation v. Dunkirk Power LLC, NRG Dunkirk Operations, Inc., Huntley Power LLC, NRG Huntley Operations, Inc., Oswego Harbor Power LLC and NRG Oswego Operations, Inc., Supreme Court, Erie County, Index No. 1-2000-8681 — Station Service Dispute (filed October 2, 2000). Niagara Mohawk Power Corporation (NiMo) seeks to recover damages 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. NiMo claims that we failed to pay retail tariff amounts for utility services commencing on or about June 11, 1999, and continuing to September 18, 2000, and thereafter. NiMo alleged breach of contract, suit on account, violation of statutory duty and unjust enrichment claims. Prior to trial, the parties entered into a Stipulation and Order filed August 9, 2002, consolidating this action with two other actions against the Huntley and Oswego subsidiaries, both of which cases assert the same claims and legal theories. On October 8, 2002, a Stipulation and Order was filed staying this action pending submission to FERC of some or all of the disputes in the action. The potential loss inclusive of amounts paid to NiMo and accrued is approximately $23.2 million for all three subsidiaries. The Company has accrued $10.5 million related to this matter.

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 to the above referenced action filed by NiMo at FERC asserting the same claims and legal theories. On November 19, 2004, FERC denied NiMo’s petition and ruled that the

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OSWEGO HARBOR POWER LLC

Huntley, Dunkirk and Oswego plants could net their service station obligations over a 30 calendar day period from the day NRG acquired the facilities. In addition, FERC ruled that neither NiMo nor the New York Public Service Commission could impose a retail delivery charge on the NRG facilities because they are interconnected to transmission and not to distribution. On April 22, 2005, FERC denied NiMo’s motion for rehearing. NiMo appealed to the U.S. Court of Appeals for the D.C. Circuit which, on May 12, 2005, ordered this appeal consolidated with several other pending station service disputes involving NiMo. As NiMo has appealed the FERC’s denial, we will not reverse any amounts accrued until such time as it is assured that our risk of loss has ceased. At this time, we cannot predict the outcome of this matter.

IBEW Local 97 Pension Benefits Dispute

In January, 2002, IBEW Local 97, or the Union, the collective bargaining representative of employees at the Company, filed a grievance against us under the Local 97/NRG Collective Bargaining Agreement, or the CBA. The Union claims that we breached the CBA by the manner in which we calculated pension benefits owed to 24 retiring bargaining unit employees under the terms of the benefit formula contained in a pension plan incorporated by reference into the CBA. Six of these employees were previously employed at Oswego. The Union previously filed an unfair labor practice charge against us with the National Labor Relations Board asserting similar claims and legal theories and that charge was dismissed. The Union’s grievance was arbitrated on February 17 and 18, and on March 10, 2005. Post hearing briefing was submitted by both sides and a decision is expected by the end of third quarter of 2005.

Electricity Consumers Resource Council v. Federal Energy Regulatory Commission, Docket No. 03-1449

On December 19, 2003 the Electricity Consumers Resource Council, or ECRC, appealed to the U.S. Court of Appeals for the District of Columbia Circuit a 2003 FERC decision 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. On December 3, 2004, the Company filed a brief opposing the ECRC request.

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

     Pursuant to the requirements of Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies,” and related guidance, the Company records reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss is reasonably estimable. Management has assessed each of these matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought and the probability of success. Management’s judgment may, as a result of facts arising prior to resolution of these matters or other factors, prove inaccurate and investors should be aware that such judgment is made subject to the known uncertainty of litigation.

15. Regulatory Issues

     On January 7, 2005, NYISO filed proposed LICAP demand curves for the following capability years: 2005-06, 2006-07 and 2007-08. Under the NYISO proposal, the LICAP price for New York City generation would be $126 per KW year for the capacity year 2006-07. In addition, the NYISO requested a rate of $67 per KW year for the capacity year 2006-07 for the rest of New York State excluding Long Island. On January 28, 2005, the Company filed a protest at FERC asserting the LICAP price for New York City for 2006-07 should be at least $140 per KW year. On April 21, 2005 FERC accepted the proposed demand curve with some modification. It is anticipated that capacity prices for New York state, including New York City and Long Island, will probably increase by $1 per KW year. The FERC’s modification should increase the capacity prices in New York state but the existing In-City mitigation measures would prevent us from obtaining these higher prices.

21

OSWEGO HARBOR POWER LLC

Our New York City generation is presently subject to price mitigation in the installed capacity market. When the capacity market is tight, the price we receive is limited by the mitigation price. However when the New York City capacity market is not tight, such as during the winter season, the proposed demand curve price levels should increase our revenues from capacity sales.

16. 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 of the earliest period presented, as if the Company had prepared separate filings. 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. 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 provision (benefit) for income taxes consists of the following:

	Reorganized Company						Predecessor Company
				Period from			Period from
	For the Year			December 6,			January 1,			For the Year
	Ended			2003 to			2003 to			Ended
	December 31,			December 31,			December 5,			December 31,
	2004			2003			2003			2002
	(In thousands of dollars)
Current
Federal	$	4,392		$	140		$	4,255		$	5,183
State		1,017			32			986			1,200
		5,409			172			5,241			6,383
Deferred
Federal		(3,170	)		(289	)		540			496
State		(734	)		(67	)		125			115
		(3,904	)		(356	)		665			611
Total income tax expense (benefit)	$	1,505		$	(184	)	$	5,906		$	6,994
Effective tax rate		39.9	%		39.8	%		39.9	%		39.9	%

The pre-tax income (loss) was as follows:

	Reorganized Company					Predecessor Company
			For the			For the
			Period from			Period from
	For the Year		December 6,			January 1,		For the Year
	Ended		2003 to			2003 to		Ended
	December 31,		December 31,			December 5,		December 31,
	2004		2003			2003		2002
	(In thousands of dollars)					(In thousands of dollars)
U.S.	$	3,919	$	(611	)	$	14,813	$	17,539

22

OSWEGO HARBOR POWER LLC

     The components of the net deferred income tax liabilities (assets) were:

	December 31,		December 31,
	2004		2003
	(In thousands of dollars)
Deferred tax liabilities
Difference between book and tax basis of property	$	80,351	$	79,255
Emissions credits		10,717		14,632
Other		234		213
Total deferred tax liabilities		91,302		94,100
Deferred tax assets
Other		229		66
Total deferred tax assets (before valuation allowance)		229		66
Valuation allowance		—		—
Net deferred tax assets		229		66
Net deferred tax liabilities	$	91,073	$	94,034

     The net deferred tax liabilities consist of:

	December 31,		December 31,
	2004		2003
	(In thousands of dollars)
Current deferred tax liabilities	$	—	$	28
Noncurrent deferred tax liabilities		91,073		94,006
Net deferred tax liabilities	$	91,073	$	94,034

     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
	For the Year						December 6,					January 1,				For the Year
	Ended						2003 to					2003 to				Ended
	December 31,						December 31,					December 5,				December 31,
	2004						2003					2003				2002
				(In thousands of dollars)
Income (loss) before taxes	$	3,919					$	(611	)			$	14,813			$	17,539
Tax at 35%		1,372			35.0	%		(214	)	35.0	%		5,184	35.0	%		6,139	35.0	%
State taxes (net of federal benefit)		192			4.9	%		(22	)	4.8	%		722	4.9	%		855	4.9	%
Other		(59	)		(1.5	%)		52		(8.5	%)		—	—			—	—
Income tax expense (benefit)	$	1,505			38.4	%	$	(184	)	31.3	%	$	5,906	39.9	%	$	6,994	39.9	%

23

EX-99.7

EXHIBIT 99.7

NRG INTERNATIONAL LLC AND SUBSIDIARIES

Consolidated Financial Statements
At December 31, 2004 and 2003
and for the Year Ended December 31, 2004,
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

1

NRG INTERNATIONAL LLC AND SUBSIDIARIES

INDEX

	Page
Reports of Independent Registered Public Accounting Firms		3
Consolidated Balance Sheets at December 31, 2004 and 2003		6
Consolidated Statements of Operations for the year ended December 31, 2004, 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		7
Consolidated Statements of Member’s Equity and Comprehensive Income for the year ended December 31, 2004, 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		8
Consolidated Statements of Cash Flows for the year ended December 31, 2004, 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		9
Notes to Consolidated Financial Statements		10

2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Member of
NRG International LLC

     We have audited the accompanying consolidated balance sheet of NRG International LLC and its subsidiaries as of December 31, 2004, and the related consolidated statements of operations, member’s equity and comprehensive income, and cash flows for the year then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

     We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

     In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of NRG International LLC and it's subsidiaries as of December 31, 2004, and the results of their operations and their cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles.

/S/	KPMG LLP
	KPMG LLP

Philladelphia, Pennsylvania
May 27, 2005

3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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 comprehensive income, 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 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 audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 audit provides a reasonable basis for our opinion.

     As discussed in Notes 1 and 2 to the consolidated financial statements, on May 14, 2003, NRG Energy, Inc. and certain of its subsidiaries, excluding 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 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
October 29, 2004

4

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Member of
NRG International LLC

     In our opinion, the accompanying consolidated statements of operations, of member’s equity and comprehensive income, and of cash flows present fairly, in all material respects, the results of operations and cash flows of NRG International LLC and its subsidiaries (“Predecessor Company”) for the period from January 1, 2003 to December 5, 2003 and for the year 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). 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 Notes 1 and 2 to the consolidated financial statements, on May 14, 2003, NRG Energy, Inc. and certain of its subsidiaries, excluding 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 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
October 29, 2004

5

NRG INTERNATIONAL LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	Reorganized Company
	December 31,		December 31,
	2004		2003
	(In thousands of dollars)
ASSETS
Current assets
Cash and cash equivalents	$	177,389	$	127,020
Restricted cash		59,517		45,874
Accounts receivable, less allowance for doubtful accounts of $0 and $0, respectively		59,875		40,309
Accounts receivable — affiliates		—		5,404
Current portion of notes receivable		85,124		64,720
Inventory		20,713		17,900
Prepayments and other current assets		5,157		3,790
Current deferred income taxes		—		754
Current assets — discontinued operations		—		12,615
Total current assets		407,775		318,386
Property, plant and equipment, net of accumulated depreciation of $26,800 and $1,467, respectively		456,401		458,224
Equity investments in affiliates		401,727		332,617
Notes receivable, less current portion		433,962		444,052
Notes receivable — affiliate		119,666		111,913
Derivative instruments valuation		34,926		59,907
Other assets		3,376		4,450
Noncurrent assets — discontinued operations		—		47,476
Total assets	$	1,857,833	$	1,777,025
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Capital leases	$	69,904	$	75,944
Notes payable — affiliate		57,344		10,664
Accounts payable		36,231		30,271
Accounts payable — affiliate		15,905		2,976
Accrued income taxes		4,965		18,673
Accrued liabilities		8,454		4,471
Current deferred income taxes		93		—
Other current liabilities		996		1,839
Current liabilities — discontinued operations		—		62,993
Total current liabilities		193,892		207,831
Other liabilities
Capital leases		233,898		266,526
Notes payable — affiliate		155,496		198,300
Deferred income taxes		164,897		165,883
Postretirement and other benefit obligations		8,605		14,016
Derivative instruments valuation		112,447		112,047
Other long-term obligations		20,409		14,959
Noncurrent liabilities — discontinued operations		—		3,729
Total liabilities		889,644		983,291
Commitments and contingencies
Member’s equity		968,189		793,734
Total liabilities and member’s equity	$	1,857,833	$	1,777,025

The accompanying notes are an integral part of these consolidated financial statements.

6

NRG INTERNATIONAL LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

		Reorganized Company						Predecessor Company
					For the Period			For the Period
		Year Ended			December 6 -			January 1 -			Year Ended
		December 31,			December 31,			December 5,			December 31,
		2004			2003			2003			2002
	(In thousands of dollars)
Revenues		$	315,669		$	23,358		$	271,665		$	279,750
Operating costs			258,353			18,754			212,917			236,378
Depreciation and amortization			24,044			1,475			15,847			15,000
General and administrative expenses			11,138			993			9,278			9,824
Restructuring and impairment charges			—			—			3,929			53,501
Income (loss) from operations			22,134			2,136			29,694			(34,953	)
Minority interest in losses of consolidated subsidiaries			—			—			—			(470	)
Equity in earnings of unconsolidated affiliates			68,445			1,707			61,900			49,297
Write downs and losses on sales of equity method investments			(1,268	)		—			(138,371	)		(139,146	)
Other income, net			13,574			1,148			443			8,179
Interest expense			(12,025	)		(709	)		(7,021	)		(7,239	)
Income (loss) from continuing operations before income taxes			90,860			4,282			(53,355	)		(124,332	)
Income tax expense			8,707			796			11,363			13,743
Income (loss) from continuing operations			82,153			3,486			(64,718	)		(138,075	)
Income (loss) on discontinued operations, net of income taxes			7,517			(222	)		169,183			(553,008	)
Net income (loss)		$	89,670		$	3,264		$	104,465		$	(691,083	)

The accompanying notes are an integral part of these consolidated financial statements.

7

NRG INTERNATIONAL LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY
AND COMPREHENSIVE INCOME/(LOSS)

											Accumulated
											Other
					Member			Accumulated			Comprehensive			Total
	Member				Contributions/			Net Income			Income			Member’s
	Units		Amount		Distributions			(Loss)			(Loss)			Equity
					(In thousands of dollars)
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 income		—		—		—			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
Net income		—		—		—			89,670			—			89,670
Foreign currency translation adjustments and other		—		—		—			—			43,514			43,514
Impact of SFAS No. 133 for the year ending December 31, 2004, net of taxes of $0.7 million		—		—		—			—			3,863			3,863
Comprehensive income															137,047
Contribution from member		—		—		37,408			—			—			37,408
Balances at December 31, 2004 (Reorganized Company)		1,000	$	1	$	808,664		$	92,934		$	66,590		$	968,189

The accompanying notes are an integral part of these consolidated financial statements.

8

NRG INTERNATIONAL LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Reorganized Company						Predecessor Company
				For the Period			For the Period
	Year Ended			December 6 -			January 1 -			Year Ended
	December 31,			December 31,			December 5,			December 31,
	2004			2003			2003			2002
				(In thousands of dollars)
Cash flows from operating activities
Net income (loss)	$	89,670		$	3,264		$	104,465		$	(691,083	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Distributions (less than) in excess of equity earnings of unconsolidated affiliates		(38,684	)		5,549			(53,580	)		(25,893	)
Write downs and losses on sales of equity method investments		1,268			—			138,371			139,146
Restructuring and impairment charges		—			—			3,929			620,193
Depreciation and amortization		24,528			2,011			23,742			51,051
Amortization of debt premium		(1,002	)		—			—			—
Bad debt expense		—			—			(14,255	)		—
Unrealized (gains) losses on derivatives		(4,932	)		391			(122,937	)		17,368
Unrealized exchange (gains) losses		—			(310	)		(2,663	)		2,290
Deferred income taxes		(8,399	)		(2,374	)		39,790			7,287
Minority interest		(43	)		(17	)		(1,793	)		(21,655	)
Gain on disposal of discontinued operations		(10,280	)		—			(164,126	)		(18,690	)
Deferred income		—			—			—			13,890
Amortization of out-of-market power contracts		29,510			3,048			6,543			1,889
Changes in assets and liabilities
Accounts receivable – affiliate and non-affiliate		6,889			2,265			(48,863	)		10,220
Inventory		(1,958	)		(1,186	)		(2,307	)		(957	)
Prepayments and other current assets		(1,114	)		(436	)		(3,519	)		15,284
Accounts payable – affiliate and non-affiliate		2,072			(1,265	)		(6,410	)		(28,537	)
Accrued interest		65			(4,554	)		3,157			1,439
Accrued income taxes		(13,394	)		945			(2,733	)		8,222
Accrued and other current liabilities		6,775			(850	)		8,080			(2,009	)
Changes in other assets and liabilities		(1,758	)		(1,307	)		15,367			(8,242	)
Net cash provided by (used in) operating activities		79,213			5,174			(79,742	)		91,213
Cash flows from investing activities
Investments in affiliates		—			(3,475	)		(44,728	)		(91,859	)
Capital expenditures		(20,291	)		(1,080	)		(69,487	)		(61,421	)
Acquisitions, net of liabilities assumed		—			—			—			(411	)
Proceeds from sale of investments		26,693			(10	)		35,117			32,916
Change in note receivable		24,663			—			64,901			—
Proceeds from sale of discontinued operations		224			263			164,078			27,259
Increase in restricted cash		(10,960	)		—			(18,253	)		(18,274	)
Net cash (used in) provided by investing activities		20,329			(4,302	)		131,628			(111,790	)
Cash flows from financing activities
Proceeds from issuance of debt		20,159			—			62,300			7,034
Contribution from member		—			—			—			113,862
Repayments on note payable – affiliate and capital leases		(71,667	)		(2,370	)		(42,013	)		(42,880	)
Distributions to member		—			—			(112,000	)		—
Net cash (used in) provided by financing activities		(51,508	)		(2,370	)		(91,713	)		78,016
Effect of exchange rate changes on cash and cash equivalents		1,614			2,323			(53,767	)		20,166
Increase in cash from discontinued operations		721			281			26,646			50,939
Net change in cash and cash equivalents		50,369			1,106			(66,948	)		128,544
Cash and cash equivalents
Beginning of period		127,020			125,914			192,862			64,318
End of period	$	177,389		$	127,020		$	125,914		$	192,862
Supplemental disclosures of cash flow information
Non-cash investing activities
Reduction to fixed assets due to liquidated damages	$	14,543		$	—		$	—		$	—
Non-cash financing activities
Reduction to notes payable – affiliate due to transfer to accounts payable — affiliate	$	10,664		$	—		$	—		$	—

The accompanying notes are an integral part of these consolidated financial statements.

9

NRG INTERNATIONAL LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization

     NRG International LLC, or 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., or NRG Energy.

     The Company was formed for the purpose of financing, acquiring, owning, operating and maintaining, through its subsidiaries and affiliates, certain non-U.S. power generation facilities owned by NRG Energy, which includes Flinders Power, or Flinders, in Australia and Saale Energie GmbH, or SEG, in Germany. Flinders is comprised of two power stations generating 760 MW and a coal mine which sells electricity into the South Australian market. SEG owns a 400 MW coal powered power station located in Halle, Germany and sells output to Vattenfall Europe A.G., or VEG, under a power purchase agreement. In addition, the Company holds various investments in projects accounted for under the equity method. See Note 10.

     At December 31, 2004, the Company owned total interests in five power projects in three countries having an aggregate generation capacity of approximately 2,000 MW in various international markets. These power projects include Flinders and Gladstone Power Project (a 37.5% owned equity investment) in Australia, SEG and Mibrag (a 50% owned equity investment) in Germany and Enfield (a 25% owned equity investment) in England.

      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. All NRG Energy entities have emerged from Chapter 11. 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.

2. Summary of Significant Accounting Policies

   Principles of Consolidation and Basis of Presentation

     For financial reporting purposes, close of business on December 5, 2003, represents the date of NRG Energy’s emergence from bankruptcy. 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, prior to December 6, 2003
“Reorganized Company”	The Company, after push down accounting
	The Company’s operations, December 6, 2003 — December 31, 2004

     The consolidated financial statements include the accounts of the Company and its subsidiaries in which we have a controlling interest. All significant intercompany transactions and balances have been eliminated in consolidation. As discussed in Note 10, the Company has investments in joint ventures and partnerships. Earnings from equity in international investments are recorded net of foreign income taxes.

   Fresh Start Reporting/Push Down Accounting

     In accordance with SOP 90-7, 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 immediately before confirmation receive less than 50 percent of the voting shares of the emerging entity. NRG Energy met these requirements and adopted Fresh Start reporting resulting in the creation of a new reporting entity designated as Reorganized NRG. 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.

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NRG INTERNATIONAL LLC AND SUBSIDIARIES

     The bankruptcy court issued a confirmation order approving 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. The Excel Energy settlement agreement was entered into on December 5, 2003. NRG Energy believed 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, 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 SFAS No. 109, “Accounting for Income Taxes”. The net effect of all Fresh Start adjustments resulted in a gain of $3.9 billion (comprised of a $4.1 billion gain from continuing operations and a $0.2 billion loss from discontinued operations), 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 and push down accounting 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 NRG Energy’s 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 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. 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.

     Due to the adoption of Fresh Start upon NRG Energy’s emergence from bankruptcy and the impact of push down accounting, the Reorganized Company’s 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.

   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 the Company’s projects that are restricted in their use. These funds are used to pay for current operating expenses and current debt service payments, per the restrictions of the debt agreements.

   Inventory

     Inventory is valued at the lower of weighted average cost or market and consists principally of fuel oil, spare parts and coal.

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NRG INTERNATIONAL LLC AND SUBSIDIARIES

   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. On 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 following 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.

Facilities and equipment	10 to 40 years
Office furnishings and equipment	3 to 15 years

   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 $3.3 million for the year ended December 31, 2004, $0.7 million and $5.4 million for the periods December 6, 2003 to December 31, 2003 and January 1, 2003 to December 5, 2003, respectively, and $1.2 million for the year ended December 31, 2002.

   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.

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NRG INTERNATIONAL LLC AND SUBSIDIARIES

   Fair Value of Financial Instruments

     The carrying amount of cash and cash equivalents, restricted cash, receivables, accounts payables and accrued liabilities approximate fair value because of the short maturity of these instruments. The carrying amounts of long-term notes receivables approximate fair value, as the effective rates for these instruments are comparable to market rates at year-end, including current portion. The fair value of long-term debt is 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 resulting from the tax provision are reflected as a contribution by member in the consolidated statement of member’s 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.

   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 are recorded at cost and their carrying values are 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 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 transmission to the customer. Capacity and ancillary revenue is recognized when contractually earned.

     The Company provides contract operations and maintenance services to certain unconsolidated affiliates. Revenue is recognized as contract services are performed.

   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 translation gains or losses are reported in results of operations. The Company recognized foreign currency translation gains of $1.3 million for the year ended December 31, 2004, $0.3 million and $0.5 million for the periods December 6, 2003 to December 31, 2003 and January 1, 2003 to December 5, 2003, respectively, and $0.8 million for the year ended December 31, 2002.

   Other Income

      The Company recognizes other income for interest income on loans to unconsolidated affiliates, as the interest is earned and realizable, either through monthly cash payments and/or annual dividends.

   Credit Risk

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NRG INTERNATIONAL LLC AND SUBSIDIARIES

     Credit risk relates to the risk of loss resulting from non-performance or non-payment by counter-parties pursuant to the terms of their contractual obligations. NRG Energy monitors and manages the credit risk of the Company and its subsidiaries through credit policies which include an (i) established credit approval process, (ii) daily monitoring of counter-party credit limits, (iii) the use of credit mitigation measures such as margin, collateral, credit derivatives or prepayment arrangements, (iv) the use of payment netting agreements and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counter-party. Risk surrounding counter-party performance and credit could ultimately impact the amount and timing of expected cash flows. NRG Energy has credit protection within various agreements to call on additional collateral support if necessary.

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

   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 determined), 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 member’s equity as previously reported.

   Recent Accounting Pronouncements

     In November 2004, the Emerging Issue Task Force, or EITF, issued EITF No. 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations”. EITF 03-13 clarifies the definition of cash flows of a component in which the seller engages in activities with the component after disposal, and significant continuing involvement in the operations of the component after the disposal transaction, and is effective for fiscal periods beginning after December 15, 2004. We will apply this standard to any new discontinued operations effective January 1, 2005.

     In November 2004, the FASB issued SFAS No. 151, “Inventory Costs — an amendment of ARB No. 43, Chapter 4”. This statement amends the guidance in ARB No. 43, Chapter 4, “Inventory Pricing”, and requires that idle facility expense, excessive spoilage, double freight, and rehandling costs be recognized as current-period charges regardless of whether they meet the criterion of “so abnormal” established by ARB No. 43. SFAS No. 151 is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. We are currently in the process of evaluating the potential impact that the adoption of this statement will have on our consolidated financial position and results of operations.

     In December 2004, the FASB issued two FASB Staff Positions, or FSPs, regarding the accounting implications of the American Jobs Creation Act of 2004 related to (1) the deduction for qualified domestic production activities (FSP FAS 109-1) and (2) the one-time tax benefit for the repatriation of foreign earnings (FSP FAS 109-2). In FSP FAS 109-1, “Application of FASB Statement No. 109, “Accounting for Income Taxes,” to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004”, the Board decided that the deduction for qualified domestic production activities should be accounted for as a

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NRG INTERNATIONAL LLC AND SUBSIDIARIES

special deduction under FASB Statement No. 109, “Accounting for Income Taxes” and rejected an alternative view to treat it as a rate reduction. Accordingly, any benefit from the deduction should be reported in the period in which the deduction is claimed on the tax return. FSP FAS 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004”, addresses the appropriate point at which a company should reflect in its financial statements the effects of the one-time tax benefit on the repatriation of foreign earnings. Because of the proximity of the Act’s enactment date to many companies’ year-ends, its temporary nature, and the fact that numerous provisions of the Act are sufficiently complex and ambiguous, the Board decided that absent additional clarifying regulations, companies may not be in a position to assess the impact of the Act on their plans for repatriation or reinvestment of foreign earnings. Therefore, the Board provided companies with a practical exception to FAS 109’s requirements by providing them additional time to determine the amount of earnings, if any, that they intend to repatriate under the Act’s beneficial provisions. The Board confirmed, however, that upon deciding that some amount of earnings will be repatriated, a company must record in that period the associated tax liability, thereby making it clear that a company cannot avoid recognizing a tax liability when it has decided that some portion of its foreign earnings will be repatriated. The Company does not believe that the potential adoption of FSP 109-1 will have a material impact on our consolidated financial position and results of operation. The Company is currently in the process of evaluating the potential impact that the adoption of FSP FAS 109-2 will have on our consolidated financial position and results of operations.

     In March 2005, the Financial Accounting Standards Board (FASB) issued Interpretation No. 47 (FIN 47) to Financial Accounting Standard No. 143 (SFAS No. 143) governing the application of Asset Retirement Obligations. FIN 47 clarifies that the term “conditional asset retirement obligation” as used in SFAS 143. SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional but there may remain some uncertainty as to the timing and/or method of settlement. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred — generally upon acquisition, construction, or development and/or through the normal operation of the asset. SFAS No. 143 acknowledges that in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation. FIN 47 clarifies when the company would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective for fiscal years ending after December 15, 2005 and we are currently evaluating the impact of this guidance.

3. Emergence from Bankruptcy and Fresh Start Reporting

     In accordance with the requirements of SFAS No. 141, “Business Combinations” and push down accounting, the Company’s fair value of $771.3 million as of the fresh start date 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.

     Due to the adoption of push down accounting as of December 5, 2003, the Reorganized Company’s 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.

     The effects of the push down accounting adjustments on the Company’s condensed consolidated balance sheet as of December 5, 2003 were as follows:

	Predecessor					Reorganized
	Company					Company
	December 5,		Push Down			December 6,
	2003		Adjustments			2003
Current assets	$	314,144	$	190		$	314,334
Non-current assets		1,480,627		(56,914	)		1,423,713
Total Assets	$	1,794,771	$	(56,724	)	$	1,738,047
Current liabilities		292,089		(83,259	)		208,830
Non-current liabilities		774,398		(16,438	)		757,960
		1,066,487		(99,697	)		966,790
Members’ Equity		728,284		42,973			771,257
Total Liabilities and Member’s Equity	$	1,794,771	$	(56,724	)	$	1,738,047

4. Discontinued Operations

     The Company has classified assets and liabilities and revenues and expenses of 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, prior period operating results have been restated to report the operations as discontinued.

     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

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NRG INTERNATIONAL LLC AND SUBSIDIARIES

their classification as such.

     The assets and liabilities of the discontinued operations are reported in the December 31, 2004 and 2003 consolidated balance sheets as discontinued operations. The major classes of assets and liabilities are presented in the following table. As of December 31, 2004 all projects have been sold. The discontinued assets and liabilities as of December 31, 2003, consist of the Hsin Yu project.

	Reorganized Company
	December 31,		December 31,
	2004		2003
	(In thousands of dollars)
Cash	$	—	$	721
Receivables, net		—		5,121
Inventory		—		2,784
Other current assets		—		3,989
Current assets — discontinued operations	$	—	$	12,615
Property, plant and equipment, net	$	—	$	39,838
Other noncurrent assets		—		7,638
Noncurrent assets — discontinued operations	$	—	$	47,476
Current portion of long-term debt	$	—	$	40,820
Accounts payable — trade		—		16,401
Other current liabilities		—		5,772
Current liabilities — discontinued operations	$	—	$	62,993
Other long-term obligations		—		3,729
Noncurrent liabilities — discontinued operations	$	—	$	3,729

     For the year ended December 31, 2004 and 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 the Company’s Hsin Yu, Killingholme, Cahua and Energia Pacasmayo projects. For the year ended December 31, 2002, discontinued results of operations included the Company’s Hsin Yu, Killingholme, Cahua, Energia Pacasmayo, Csepel and Entrade projects. Summarized results of operations of the discontinued operations were as follows.

	Reorganized Company						Predecessor Company
				For the Period			For the Period
	Year Ended			December 6 -			January 1 -			Year Ended
	December 31,			December 31,			December 5,			December 31,
	2004			2003			2003			2002
	(In thousands of dollars)
Operating revenues	$	8,266		$	4,213		$	98,224		$	644,969
Operating costs and other expenses		11,113			4,435			93,504			1,224,079
Pre-tax (loss) income from operations of discontinued components		(2,847	)		(222	)		4,720			(579,110	)
Income tax benefit		(84	)		—			(337	)		(7,412	)
(Loss) income from operations of discontinued components		(2,763	)		(222	)		5,057			(571,698	)
Disposal of discontinued components		10,280			—			164,126			18,690
Net income (loss) on discontinued operations	$	7,517		$	(222	)	$	169,183		$	(553,008	)

     Operating costs and other expenses for the year December 31, 2002, shown in the table above included asset impairment charges of approximately $599.8 million. The 2002 charges are comprised of approximately $477.9 million for the Killingholme project and $121.9 million for the Hsin Yu project. There were no impairment charges during the year ended December 31, 2004, or during the periods December 6, 2003 to December 31, 2003 and January 1, 2003 to December 5, 2003.

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

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NRG INTERNATIONAL LLC AND SUBSIDIARIES

	Reorganized Company					Predecessor Company
				For the Period		For the Period
	Year Ended			December 6 -		January 1-			Year Ended
	December 31,			December 31,		December 5,			December 31,
	2004			2003		2003			2002
	(In thousands of dollars)
Discontinued operations
Current
U.S	$	—		$	—	$	—		$	—
Foreign		—			—		(741	)		(8,064	)
		—			—		(741	)		(8,064	)
Deferred
U.S		—			—		—			—
Foreign		(84	)		—		404			652
		(84	)		—		404			652
Total income tax (benefit)		(84	)		—		(337	)		(7,412	)

     Hsin Yu — During 2002, the Company recorded an impairment charge of $121.9 million. During the second quarter of 2004, the Company entered into an agreement to sell its interest in Hsin Yu power generating facility 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 $0.2 million, resulting in a gain of approximately $10.3 million resulting from the negative equity in the project. In addition, although the Company has 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.

     Killingholme — During the third quarter of 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 results from the write-down of the project’s assets in the third quarter of 2002 below the carrying value of the related debt.

     Cahua and Energia Pacasmayo — In November 2003, the Company completed the sale of the Cahua and Energia Pacasmayo projects resulting in net cash proceeds of approximately $16.2 million and a loss of $36.9 million.

     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 2002 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.

5. Write Downs and 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 losses on sales of equity method investments included in the consolidated statements of operations include the following:

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NRG INTERNATIONAL LLC AND SUBSIDIARIES

	Reorganized Company				Predecessor Company
			For the Period		For the Period
	Year Ended		December 6 -		January 1 -			Year Ended
	December 31,		December 31,		December 5,			December 31,
	2004		2003		2003			2002
	(In thousands of dollars)
Kondapalli	$	—	$	—	$	(45	)	$	12,751
ECKG		—		—		(7,938	)		—
Loy Yang	$	1,268		—		146,354			111,383
Energy Development Limited		—		—		—			13,382
Collinsville Power Station		—		—		—			1,630
Total write downs and losses of equity method investment	$	1,268	$	—	$	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, or Genting, to sell its 30% interest in Lanco Kondapalli Power Pvt Ltd, or Kondapalli, and a 74% interest in Eastern Generation Services (India) Pvt Ltd. 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 our investment of approximately $111.4 million during 2002. This write-down reflected management’s belief that the decline in fair value of the investment was other than temporary. 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. Consequently, the Company recorded an additional impairment charge of approximately $146.4 million during 2003. In April 2004 the Company completed the sale of Loy Yang which resulted in net cash proceeds of $26.7 million and a loss of $1.3 million.

     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, 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. 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 AUD 78.5 million (approximately U.S. $43.9 million), in exchange for its ownership interest in EDL.

     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 AUD $8.6 million (approximately U.S. $4.8 million).

6. Restructuring and Impairment Charges

     The Company reviews 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 $45.7 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. There were no impairment charges for the year ended December 31, 2004 and for the period December 6, 2003 to December 31, 2003.

     To determine whether an asset was impaired, the Company compared asset carrying values to total future estimated undiscounted cash flows. If an asset was determined to be impaired based on the cash flow testing performed, an impairment loss was recorded to

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NRG INTERNATIONAL LLC AND SUBSIDIARIES

write down the asset to its fair value. 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:

		Reorganized Company				Predecessor Company
				For the Period		For the Period
		Year Ended		December 6 -		January 1-			Year Ended
	Project	December 31,		December 31,		December 5,			December 31,
Project Name	Status	2004		2003		2003			2002
		(In thousands of dollars)
TermoRio	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

     TermoRio — TermoRio was a 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 Petroleo Brasileiro S.A. Petrobras, or Petrobras. On May 17, 2002, Petrobras commenced an arbitration. On March 8, 2003, the arbitral tribunal decided most, but not all, of the issues in the Company’s favor and awarded the Company approximately US$80 million. On June 4, 2004, NRG Energy commenced a lawsuit in U.S. District Court for the Southern District of New York, seeking to enforce the arbitration award. On February 16, 2005, a conditional settlement agreement was signed with our former partner Petrobras, whereby Petrobras is obligated to pay the Company US$70.8 million. Such payment was received by the Company on February 25, 2005. The Company has a note receivable of $57.3 million related to the arbitration award. The amount received in excess of $57.3 million will be recorded to earnings in the first quarter of 2005. In addition to this settlement amount, the Company retains the right to continue to seek recovery of US$12.3 million in a related dispute with a third-party in Brazil.

     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, resulting in a net gain of approximately $3.1 million.

     The Company incurred $0.6 million of financial and legal advisor fees during the period January 1, 2003 to December 5, 2003 related to the restructuring of various legal functions. 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.

7. Inventory

     Inventory, which is valued at the lower of weighted average cost or market, consists of:

	Reorganized Company
	December 31,		December 31,
	2004		2003
	(In thousands of dollars)
Fuel oil	$	990	$	504
Coal		10,461		10,726
Spare parts		9,262		6,670
Total inventory	$	20,713	$	17,900

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:

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NRG INTERNATIONAL LLC AND SUBSIDIARIES

	Reorganized Company
	December 31,			December 31,
	2004			2003
	(In thousands of dollars)
Notes receivable
Termo Rio (1)	$	57,323		$	57,323
VEAG, due August 31, 2021, 13.88% (direct financing lease)(2)		461,763			451,449
		519,086			508,772
Less: current portion		(85,124	)		(64,720	)
Notes receivable — nonaffiliates	$	433,962		$	444,052
Kraftwerke Schkopau GBR, indefinite maturity date, 4.75%-7.79%(3)		119,644			111,892
Other		22			21
Notes receivable — affiliate	$	119,666		$	111,913

(1)	See Note 6 — Restructuring and Impairment Charges for an explanation of the note receivable.
(2)	Saale Energie GmbH has sold 100% of its share of energy from the Schkopau power plant under a 25-year contract to VEAG, a German utility, which is more than 83% of the useful life of the plant. The direct financing lease receivable amount was calculated based on the present value of the income to be received over the life of the contract.
(3)	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.

9. Property, Plant and Equipment

     The major classes of property, plant and equipment were as follows:

		Reorganized Company						Average
	Depreciable	December 31,			December 31,			Remaining
	Lives	2004			2003			Useful Life
Facilities and equipment (1)	10-40 years	$	456,549		$	323,837		19 years
Land, buildings and improvements			16,846			15,717
Office furnishings and equipment	3-15 years		2,406			2,081		3 years
Construction work in progress			7,400			118,056
Total property, plant and equipment			483,201			459,691
Accumulated depreciation			(26,800	)		(1,467	)
Property, plant and equipment, net		$	456,401		$	458,224

(1) During 2004, Flinders Power Partnership, or FPP, recorded a reduction in Facilities and Equipment in the amount of $18.5 million representing FFP’s contractual claim for liquidated damages from Alstom Power Ltd., or Alstom. In March 2005, FPP received a net settlement of $5.3 million after an offset from $10.7 million of outstanding invoices from Alstom.

10. Investments Accounted for by the Equity Method

     The Company has 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 ownership structure prevents the Company from exercising a controlling 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, 2004, is as follows:

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NRG INTERNATIONAL LLC AND SUBSIDIARIES

		Economic
Name	Geographic Area	Interest
Gladstone Power Station	Australia		38	%
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.

     Summarized financial information for investments in unconsolidated affiliates accounted for under the equity method is as follows:

	Reorganized Company				Predecessor Company
			For the Period			For the Period
	Year Ended		December 6 -			January 1 -			Year Ended
	December 31,		December 31,			December 5,			December 31,
	2004		2003			2003			2002
	(In thousands)
Operating revenues	$	860,210	$	98,990		$	915,798		$	993,543
Costs and expenses		761,500		96,342			1,000,974			896,588
Net income (loss)	$	98,710	$	2,648		$	(85,176	)	$	96,955
Current assets	$	373,277	$	369,800		$	378,422		$	515,614
Noncurrent assets		2,187,878		4,621,844			4,482,307			4,746,810
Total assets	$	2,561,155	$	4,991,644		$	4,860,729		$	5,262,424
Current liabilities	$	97,590	$	779,580		$	734,309		$	680,512
Noncurrent liabilities		1,673,320		3,524,886			3,450,667			3,227,514
Equity		790,245		687,178			675,753			1,354,398
Total liabilities and equity	$	2,561,155	$	4,991,644		$	4,860,729		$	5,262,424
The Company’s share of equity(3)	$	321,031	$	287,320		$	283,478		$	447,428
The Company’s carrying value(2)		401,727		332,617			326,798			309,748
The Company’s share of net income(1)		68,445		1,707			61,900			49,297

(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 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.
(3)	The Company’s share of equity increased in 2004 due to the recording of equity earnings, for previous periods, recorded net of tax for its 37.5% investment in Gladstone Power Station UJV.

     The Company has ownership in three companies that were considered significant as defined by applicable SEC regulations as of December 31, 2004: Gladstone Power Station UJV, or Gladstone, Mibrag GmbH, or Mibrag and Enfield Energy Centre Limited, or Enfield. The Company accounts for these investments using the equity method. These 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, or UJV, which operates a 1,680 megawatt coal-fueled power generation facility in Queensland, Australia. The operations of 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

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NRG INTERNATIONAL LLC AND SUBSIDIARIES

the facility is sold on the national market under a long term agreement. The following tables summarize financial information for Gladstone UJV, including interests owned by the Company and other parties for the periods shown below:

     Results of operations:

	For the Year Ended
	2004		2003		2002
	(In thousands of dollars)
Operating revenues	$	239,400	$	73,696	$	64,311
Operating income		61,878		19,052		16,387
Net income		33,241		9,049		8,449

     Financial position:

	December 31,
	2004		2003
	(In thousands of dollars)
Current assets	$	89,088	$	34,484
Other assets		585,142		215,472
Total assets	$	674,230	$	249,956
Current liabilities	$	24,792	$	22,970
Other liabilities		399,619		146,864
Equity		249,819		80,122
Total liabilities and equity	$	674,230	$	249,956

     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
	2004		2003		2002
	(In thousands of dollars)
Operating revenues	$	426,814	$	400,952	$	320,192
Operating income		55,624		61,835		66,663
Net income		42,504		45,875		56,224

     Financial position:

	December 31,
	2004		2003
	(In thousands of dollars)
Current assets	$	178,383	$	164,780
Other assets		1,295,129		1,206,934
Total assets	$	1,473,512	$	1,371,714
Current liabilities	$	20,646	$	23,198
Other liabilities		1,082,616		1,031,606
Equity		370,250		316,910
Total liabilities and equity	$	1,473,512	$	1,371,714

     At December 31, 2004, the Company owned a 25% interest in Enfield (See Note 23). Located in Enfield, North London, UK, Enfield owns and operates a 396 MW, natural gas-fired combined cycle gas turbine power station. Enfield sells electricity generated from the plant in North London and the gas generated to BG Exploration and Production Limited under a long term gas supply contract. Enfield has a long-term agreement that effectively fixes the purchase price of its gas supply. The purpose of the contract, which was executed in August of 1997 and extends through October of 2014, is to mitigate the risk associated with fluctuations in the price of gas utilized in the generation of electricity at the Company’s facility. This contract is considered a derivative as defined by FASB Statement No. 133, and is afforded

22

NRG INTERNATIONAL LLC AND SUBSIDIARIES

mark-to-market accounting treatment. We are subject to volatility in earnings associated with fluctuations in the market price of gas. Enfield has the ability to consume the gas for generation, and therefore the Company’s risk of loss associated with the contract is minimal. Given an increase in the price of natural gas in the UK market during the course of 2004, the Company recorded gains of $23.3 million associated with the value of this contract. Gains of $4 million and losses of $4.5 million were recorded in 2003 and 2002, respectively. The following tables summarize financial information for Enfield, including interests owned by the Company and other parties for the periods shown below:

     Results of operations:

	For the Year Ended
	2004		2003		2002
	(In thousands of dollars)
Operating revenues	$	184,906	$	148,491	$	89,245
Operating income		46,663		33,521		13,681
Net income		18,837		9,287		8,784

     Financial position:

	December 31,
	2004		2003
	(In thousands of dollars)
Current assets	$	91,965	$	64,088
Other assets		205,834		201,617
Total assets	$	297,799	$	265,705
Current liabilities	$	32,474	$	27,548
Other liabilities		191,085		182,759
Equity		74,240		55,398
Total liabilities and equity	$	297,799	$	265,705

     Until the completion of the sale of its interests in April 2004 (see Note 5), 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. Due to the fact that the Company sold its interests in Loy Yang as of April 2004, the Company has not been able to obtain the requisite financial information for 2004:

     Results of operations:

	For the Year Ended
	2003			2002
	(In thousands of dollars)
Operating revenues	$	382,561		$	367,278
Operating income		17,798			(76,962	)
Net (loss) income		(160,206	)		(427,971	)

     Financial position:

	December 31,
	2003
	(In thousands of
	dollars)
Current assets	$	131,994
Other assets		2,879,434
Total assets	$	3,011,428
Current liabilities	$	705,715
Other liabilities		2,156,718
Equity		148,995
Total liabilities and equity	$	3,011,428

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

23

NRG INTERNATIONAL LLC AND SUBSIDIARIES

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 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.

     The following represents the balances of the asset retirement obligation as of January 1, 2003, and related accretion for the period January 1, 2003 to December 5, 2003, the period December 6, 2003 to December 31, 2003 and for the year ended December 31, 2004. Additions to estimates are made as changes to planned asset retirement obligations are made. The asset retirement obligation is included in other long-term obligations in the consolidated balance sheet.

	(In thousands)
Balance at January 1, 2003 (Predecessor Company)	$	5,834
Accretion for the period January 1 – December 5, 2003		3,282
Balance at December 5, 2003 (Predecessor Company)	$	9,116
Balance at December 6, 2003 (Reorganized Company)	$	9,116
Accretion for the period December 6 – December 31, 2003		322
Balance at December 31, 2003 (Reorganized Company)		9,438
Addition to estimate		2,854
Accretion for the year ended December 31, 2004		1,683
Balance at December 31, 2004 (Reorganized Company)	$	13,975

12. Derivative Instruments and Hedging Activities

     SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” as amended by SFAS No. 137, SFAS No. 138 and SFAS No. 149 requires us to recognize all derivative instruments on the balance sheet as either assets or liabilities and measure them at fair value each reporting period. If certain conditions are met, we may be able to designate our derivatives as cash flow hedges and defer the effective portion of the change in fair value of the derivatives in Accumulated Other Comprehensive Income, or OCI, and subsequently recognized in earnings when the hedged items impact income. The ineffective portion of a cash flow hedge is immediately recognized in income.

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

     For derivatives that are neither designated as cash flow hedges or do not qualify for hedge accounting treatment the changes in the fair value will be immediately recognized in earnings.

     Under the guidelines, established by SFAS No. 133, as amended, certain derivative instruments may qualify for the normal purchase and sale exception and are therefore exempt from fair value accounting treatment.

     SFAS No. 133 applies to our energy related commodity contracts, interest rate swaps, and foreign exchange contracts discussed in further detail below.

Derivative Financial Instruments

   Energy Related Commodities

24

NRG INTERNATIONAL LLC AND SUBSIDIARIES

     As part of our risk management activities, we manage the commodity price risk associated with our competitive supply activities and the price risk associated with power sales from our electric generation facilities. In 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. At December 31, 2004 we had hedge and non-hedge contracts for energy related commodities financial instruments extending through December 2018.

     No ineffectiveness was recognized on commodity cash flow hedges during the year ended December 31, 2004, the periods December 6, 2003 to December 31, 2003 and January 1, 2003 to December 5, 2003, and for the year ended December 31, 2002.

     The Company’s pre-tax earnings for the year ended December 31, 2004, the periods December 6, 2003 to December 31, 2003 and January 1, 2003 to December 5, 2003, and for the year ended December 31, 2002, were affected by an unrealized gain of $21.9 million, an unrealized loss of $1.0 million, an unrealized gain of $12.6 million, and an unrealized loss of $8.3 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, 2004, the periods December 6, 2003 to December 31, 2003 and January 1, 2003 to December 5, 2003, and the year ended December 31, 2002, losses of $3.1 million, and gains of $0, $79.7 million and $35.6 million, respectively, were reclassified 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 $61.0 million on energy related derivative instruments accounted for as hedges. The Company expects to reclassify an additional $1.2 million of deferred losses to earnings during the next twelve months on energy related derivative instruments accounted for as hedges.

   Interest Rates

     We are exposed to changes in interest rates through our issuance of variable rate and fixed rate debt. In order to manage this interest rate risk, we have entered into interest-rate swap agreements. At December 31, 2004 our consolidating subsidiaries had various interest-rate swap agreements extending through September 2012 with combined notional amounts of $158 million. If these swaps had been terminated at December 31, 2004, we would have owed the counter-parties $5.2 million.

     No ineffectiveness was recognized on interest rate cash flow hedges during the year ended December 31, 2004, the periods December 6, 2003 to December 31, 2003 and January 1, 2003 to December 5, 2003, and the year ended December 31, 2002.

     The Company’s pre-tax earnings for the year ended December 31, 2004, and the periods from December 6, 2003 to December 31, 2003 and January 1, 2003 through December 5, 2003, were affected by an unrealized gain of $0.4 million, $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 year ended December 31, 2002 was decreased by an unrealized loss of $1.0 million 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, 2004, the periods December 6, 2003 to December 31, 2003 and January 1, 2003 to December 5, 2003, and for the year ended December 31, 2002, gains of $0.1 million and $0, and losses of $37.8 million and $22.9 million, respectively, were reclassified 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.

   Foreign Currency Exchange Rates

     At December 31, 2004 and 2003, neither the Company nor its consolidating subsidiaries had any outstanding foreign currency exchange contracts.

Accumulated Other Comprehensive Income

     The following table summarizes the effects of SFAS No. 133 on the Company’s accumulated other comprehensive income balance as of December 31, 2004:

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NRG INTERNATIONAL LLC AND SUBSIDIARIES

	Reorganized Company
	Energy			Interest			Foreign
Gains (Losses)	Commodities			Rate			Currency			Total
	(In thousands of dollars)
Accumulated OCI balance at December 31, 2003	$	(2,319	)	$	43		$	125		$	(2,151	)
Due to unwinding of previously deferred amounts		3,065			(126	)		(125	)		2,814
Mark to market of hedge contracts		1,527			(478	)		—			1,049
Accumulated OCI balance at December 31, 2004	$	2,273		$	(561	)	$	—		$	1,712
Losses expected to unwind from OCI during next 12 months	$	(1,180	)	$	286		$	—		$	(894	)

     The following table summarizes the effects of SFAS No. 133 on the Company’s accumulated 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	)

     The following table summarizes the effects of SFAS No. 133 on the Company’s accumulated 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

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NRG INTERNATIONAL LLC AND SUBSIDIARIES

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.

     The following table summarizes the effects of SFAS No. 133 on the Company’s accumulated 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 counter-party		(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 counter-parties. 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 year ended December 31, 2004:

	Reorganized Company
	Energy			Interest
Gains (Losses)	Commodities			Rate		Total
	(In thousands of dollars)
Revenue	$	(1,799	)	$	—	$	(1,799	)
Cost of operations		—			—		—
Equity in earnings of unconsolidated subsidiaries		23,735			414		24,149
Interest expense		—			—		—
Total statement of operations impact before tax	$	21,936		$	414	$	22,350

     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	)

27

NRG INTERNATIONAL LLC AND SUBSIDIARIES

     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	)

13. Capital Leases and Notes Payable — Affiliate

     Capital leases and notes payable – affiliate consist of the following:

							Reorganized Company
							December 31, 2004						December 31, 2003
	Stated			Effective						Fair Value						Fair Value
	Rate			Rate			Principal			Adjustment			Principal			Adjustment
	Percent									(In thousands of dollars)
Flinders Power
Partnership September 2012		(1	)		6.00	%	$	202,856		$	9,984		$	187,668		$	10,632
NRG International Inc		—			(2	)		—			—			10,664			—
							$	202,856		$	9,984		$	198,332		$	10,632
Less: Current maturities								(47,360	)		(9,984	)		(10,664	)		—
Notes payable — affiliates							$	155,496		$	—		$	187,668		$	10,632
Saale Energie GmbH,
Schkopau capital lease, due 2021		(1	)		—		$	303,802		$	—		$	342,470		$	—
Less: Current maturities								(69,904	)		—			(75,944	)		—
Capital leases							$	233,898		$	—		$	266,526		$

(1)	Distinguishes debt with various interest rates.
(2)	Non-interest bearing debt.

Notes Payable – Affiliate

     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 was payable on demand. In December 2004, the note was extinguished by transferring the balance to accounts payable – affiliate.

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NRG INTERNATIONAL LLC AND SUBSIDIARIES

Project Financings

   Flinders Power

     At December 31, 2004, Flinders Power through its Flinders Power Finance Pty (“Flinders Finance”) affiliate, has AUD 315 million available in senior debt bank financing pursuant to two bank facilities. The first is an AUD 150 million floating-rate syndicated facility that matures in September 2012. The second facility, intended to fund the refurbishment of the Playford station, allows Flinders to draw up to AUD 165 million at a floating-rate of interest on drawn amounts and matures coterminous with the first facility. As of December 31, 2004, outstanding principal was AUD 259.2 million (approximately US $202.9 million) on the two facilities. In addition, Flinders has an AUD 20.0 million (approximately US $15.7 million) working capital facility. At December 31, 2004 the facility was undrawn. Flinders agreed with the lenders to hedge not less than 60% of its floating interest exposure until September 30, 2005 and not less than 40% of its floating interest exposure through the end of the loan. Under this financing arrangement, Flinders was required to fully fund, and NRG was required to guarantee, a debt service reserve account. The reserve amount of AUD 70 million (approximately US $54.8 million) was fully funded as of December 31, 2004.

     In February 2005, Flinders amended its debt facility of AUD 279.4 million (approximately US $218.5 million) in floating-rate debt. The amendment extended the maturity to February 2017, reduced borrowing costs and reserve requirements, minimized debt service coverage ratios, removed mandatory cash sharing arrangements, and made other minor modifications to terms and conditions. The facility includes an AUD 20 million (approximately US $15.7 million) working capital and performance bond facility. NRG Flinders is required to maintain interest-rate hedging contracts on a rolling 5-year basis at a minimum level of 60% of principal outstanding. Upon execution of the amendment, a voluntary principal prepayment of AUD 50 million (approximately US $39.1 million) was made, reducing the principal balance of the term loan to AUD 209.2 million (approximately US $163.7 million) as of March 1, 2005. On March 31, 2005, Flinders made another voluntary prepayment of AUD 10.5 million (US $8.2 million), reducing the outstanding amount to AUD 198.9 million (US $153.9 million). NRG Flinders retains the right to redraw these amounts at any time. As of March 1, 2005, the revolver remained undrawn.

     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, or SEG, which then became a subsidiary of the Company, SEG entered into two agreements which qualify to be treated as capital lease agreements in accordance with SFAS 13 “Accounting For Leases”. This conclusion is further supported by the guidance of Emerging Issues Task Force No. 01-8, “Determining Whether An Arrangement Contains a Lease”. The two agreements are: (a) the “Agreement on the Surrender of the Use and Benefit” (“U&B”) between SEG and Kraftwerke Schkopau GbR, or Schkopau, and (b) the Power Supply Contract (“PPA”) between SEG and Vattenfall Europe A.G., or VEG. Both contracts transfer substantially all of the benefits and risks of SEG’s ownership interest in its share of power generation in the power plant from Schkopau to VEG. 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 VEG. 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 $303.8 million and $342.5 million at December 31, 2004 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 17 years. In addition, a direct financing lease was recorded in notes receivable in the amount of approximately $461.8 million and $451.4 million as of December 31, 2004 and 2003, respectively. See Note 8.

     Annual maturities of capital leases and notes payable-affiliate for the years ending after December 31, 2004, are as follows:

	(In thousands of dollars)
2005	$	117,264
2006		51,785
2007		38,612
2008		31,693
2009		24,803
Thereafter		242,501
	$	506,658

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NRG INTERNATIONAL LLC AND SUBSIDIARIES

     Future minimum lease payments for capital leases included above at December 31, 2004, are as follows:

	(In thousands of dollars)
2005	$	92,201
2006		71,347
2007		57,373
2008		49,394
2009		39,498
Thereafter		257,747
Total minimum obligations		567,560
Less amounts representing interest		263,758
Present value of minimum obligations		303,802
Current portion		69,904
Long-term obligations	$	233,898

14. Financial Instruments

     The estimated fair values of the Company’s recorded financial instruments are as follows:

	Reorganized Company
	December 31, 2004				December 31, 2003
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
	(In thousands of dollars)
Cash and cash equivalents	$	177,389	$	177,389	$	127,020	$	127,020
Restricted cash		59,517		59,517		45,874		45,874
Accounts receivable		59,875		59,875		40,309		40,309
Accounts receivable – affiliates		—		—		5,404		5,404
Notes receivable, including current portion		519,086		519,086		508,772		508,772
Notes receivable — affiliate		119,666		119,666		111,913		111,913
Notes payable – affiliate		212,840		212,840		208,964		208,964
Accounts payable		36,231		36,231		30,271		30,271
Accounts payable — affiliate		15,905		15,905		2,976		2,976
Capital leases, including current portion		303,802		303,802		342,470		342,470

     For cash and cash equivalents, restricted cash, accounts receivable and accounts payable, 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 capital leases and notes payable is estimated based on a present value method using current interest rates for similar instruments with equivalent credit quality.

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.

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NRG INTERNATIONAL LLC AND SUBSIDIARIES

     For the year ended December 31, 2004:

	Reorganized Company
	Power Generation
	Australia			Europe			Total
	(In thousands of dollars)
Operations
Operating revenues	$	182,664		$	133,005		$	315,669
Operating costs		157,492			100,861			258,353
Depreciation and amortization		24,027			17			24,044
General and administrative expenses		4,448			6,690			11,138
Equity in earnings in unconsolidated affiliates		17,528			50,917			68,445
Write downs and losses on sales of equity method investments		(1,268	)		—			(1,268	)
Other (expense)/income		4,990			8,584			13,574
Interest expense		(11,199	)		(826	)		(12,025	)
Income tax (benefit)/expense		(4,255	)		12,962			8,707
Net income from continuing operations		11,003			71,150			82,153
Net income from discontinued operations		—			7,517			7,517
Net income		11,003			78,667			89,670
Balance sheet
Equity investments in affiliates		156,118			245,609			401,727
Total assets		870,838			986,995			1,857,833

     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	$	12,081		$	11,277		$	23,358
Operating costs		10,075			8,679			18,754
Depreciation and amortization		1,475			—			1,475
General and administrative expenses		307			686			993
Equity in earnings in unconsolidated affiliates		997			710			1,707
Other (expense)/income		(421	)		860			439
Income tax (benefit) expense		(268	)		1,064			796
Net income from continuing operations		1,068			2,418			3,486
Net loss from discontinued operations		—			(222	)		(222	)
Net income		1,068			2,196			3,264
Balance sheet
Equity investment in affiliates		136,129			196,488			332,617
Total assets		892,458			884,567			1,777,025

     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
Equity in earnings in unconsolidated affiliates		30,364			31,536		61,900
Write downs and losses on sales of equity method investments		(146,354	)		7,983		(138,371	)
Other (expense)/income		(17,282	)		10,704		(6,578	)
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

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NRG INTERNATIONAL LLC AND SUBSIDIARIES

     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
Equity in earnings in unconsolidated affiliates		8,692			40,605			49,297
Write downs and losses on sales of equity method investments		(139,146	)		—			(139,146	)
Other (expense)/income		(12,536	)		13,006			470
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	)

16. Income Taxes

     The Company is included in the consolidated income tax return filings of NRG Energy. Reflected in the financial statements and notes below are federal, state and international tax provisions as if the Company had prepared separate filings. The Company’s parent, NRG Energy, does not have a tax allocation agreement with its subsidiaries. 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 income tax provision (benefit) from continuing operations consists of the following amounts:

	Reorganized Company						Predecessor Company
				For the Period			For the Period
	Year Ended			December 6 -			January 1-		Year Ended
	December 31,			December 31,			December 5,		December 31,
	2004			2003			2003		2002
	(In thousands)
Current
U.S. — Federal	$	—		$	—		$	—	$	250
Foreign		13,256			1,283			10,985		12,227
		13,256			1,283			10,985		12,477
Deferred
U.S. — Federal		—			—			—		1,016
Foreign		(4,549	)		(487	)		378		250
		(4,549	)		(487	)		378		1,266
Total income tax expense	$	8,707		$	796		$	11,363	$	13,743

32

NRG INTERNATIONAL LLC AND SUBSIDIARIES

     The following represents the domestic and foreign income components of income (loss) from continuing operations before income tax expense (benefit):

	Reorganized Company					Predecessor Company
				For the Period		For the Period
	Year Ended			December 6 -		January 1 -			Year Ended
	December 31,			December 31,		December 5,			December 31,
	2004			2003		2003			2002
	(In thousands of dollars)
U.S	$	(4	)	$	28	$	(2,597	)	$	(284	)
Foreign		90,864			4,254		(50,758	)		(124,048	)
	$	90,860		$	4,282	$	(53,355	)	$	(124,332	)

     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 Period					For the Period
	Year Ended					December 6 -					January 1 -					Year Ended
	December 31,					December 31,					December 5,					December 31,
	2004					2003					2003					2002
	(In thousands)
Income (loss) before taxes	$	90,860				$	4,282				$	(53,355	)			$	(124,332	)
Tax at 35%		31,801		35.0	%		1,498		35.0	%		(18,674	)	35.0	%		(43,517	)	35.0	%
State taxes (net of federal benefit)		—		0.0	%		—		0.0	%		—		0.0	%		(41	)	0.0	%
Foreign tax		(23,094	)	(25.4	)%		(583	)	(13.6	)%		29,758		(55.8	)%		54,007		(43.4	)%
Other		—		0.0	%		(119	)	(2.8	)%		279		(0.5	)%		3,294		(2.7	)%
Income tax expense	$	8,707		9.6	%	$	796		18.6	%	$	11,363		(21.3	)%	$	13,743		(11.1	)%

     The effective tax rate may vary from year to year depending upon, among other factors, the geographic mix of earnings and losses taxed by the respective local jurisdictions. In addition, investments recorded pursuant to the equity method of accounting reflect equity earnings, net of tax assessed by the local jurisdiction.

     The components of the net deferred income tax liabilities were:

	Reorganized Company
	December 31, 2004						December 31, 2003
	U.S.			Foreign			U.S.			Foreign
	(In thousands)
Deferred tax liabilities
Difference between book and tax basis of property	$	—		$	225,028		$	—		$	361,888
Deferred tax assets
Tax loss carryforwards		—			62,736			2,648			337,614
Net unrealized gains on mark to market transactions		—			23,244			—			11,502
Investments in projects		—			—			1,487			—
Other		1			—			—			—
Total deferred tax assets (before valuation allowance)		1			85,980			4,135			349,116
Valuation allowance		(1	)		(25,942	)		(4,135	)		(152,357	)
Net deferred tax assets		—			60,038			—			196,759
Net deferred tax liabilities	$	—		$	164,990		$	—		$	165,129

     The net deferred tax liabilities (assets) consists of:

	Reorganized Company
	December 31, 2004		December 31, 2003
	(In thousands)
Current deferred tax liabilities (assets)	$	93	$	(754	)
Noncurrent deferred tax liabilities		164,897		165,883
Net deferred tax liabilities	$	164,990	$	165,129

33

NRG INTERNATIONAL LLC AND SUBSIDIARIES

     As of December 31, 2004, the Company had net operating losses related to Australia of $122.6 million and $75.2 million related to the Netherlands. The tax effected foreign loss carryforwards recorded related to these gross net operating losses were $36.8 million and $25.9 million, respectively, related to Australia and the Netherlands. The carryforward net operating losses have an indefinite life.

     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, 2004, the Company believes that it is more likely than not that no benefit will be received for the Netherlands net operating loss deferred tax assets. Therefore, a full valuation allowance of $25.9 million has been provided.

     A significant portion of the valuation allowance, as of December 31, 2003, related to the Loy Yang project, which was sold in April 2004. The fluctuations in the valuation allowance between the periods shown above were primarily due to the sale of this project.

     At December 31, 2004, 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. As of December 31, 2004, no U.S. income tax benefit was provided on the cumulative amount of losses from the Company of $110.0 million. The Company’s management is currently reviewing its reinvestment plan pursuant to the American Jobs Creation Act of 2004. This legislation provides for a low tax cost on earnings repatriated in 2005 and reinvested in a company’s U.S. operations.

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NRG INTERNATIONAL LLC AND 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, or 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 Fresh Start accounting, the Company recorded a liability of approximately $13.8 million at December 6, 2003, to record its projected benefit obligation on the consolidated balance sheet based on the fair value of the plan assets and the funded status. The consolidated balance sheet includes a liability related to the Flinders retirement plan of $8.5 million and $13.7 million at December 31, 2004 and 2003, respectively. Flinders Power made contributions of $10.2 million, $0, $4.5 million and $5.8 million for the year ended December 31, 2004, the periods December 6, 2003 to December 31, 2003 and 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 EISS assets. The assets may be invested in government securities, shares, property and a variety of other securities and the Superannuation Board may appoint professional investment managers to invest all or part of the assets on its behalf.

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 2010. Rental expense under these operating leases was $0.6 million for the year ended December 31, 2004, $0 for the period December 6, 2003 to December 31, 2003, $0.5 million for the period January 1, 2003 to December 5, 2003, and $0 for the year ended December 31, 2002, respectively. Future minimum lease payments under these leases for the years ending after December 31, 2004, are as follows:

	(In thousands of dollars)
2005	$	1,007
2006		761
2007		615
	$	2,383

   Matra Powerplant Holding B.V.

     Matra Powerplant Holding B.V. , or Matra, is presently involved in a dispute with the Dutch tax authorities. 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 Powerplant Holding B.V. The shareholders of Matra Powerplant Holding B.V. granted interest-free loans to Matra Powerplant Holding B.V. based upon a favorable tax ruling granted to NRGenerating International B.V. in 1994.

     The tax authorities consider the loans to be informal capital contributions (so-called participatory loans) and thereby refuse the interest deductions of Matra Powerplant Holding B.V. in the subsequent years. To date it is unclear whether these types of interest free loans should be considered as capital contributions.

     The tax authorities issued the following statutory notices of deficiency and tax assessments:

1998 Notice of Deficiency	Corporate Income Tax 35%	EUR	518,723
1998 Notice of Deficiency	Capital Duty 1%	EUR	615,179
2001 Assessment	Corporate Income Tax 35%	EUR	1,702,349

     Appeals have been filed against the notices of deficiency and tax assessments. For the 1998 corporate income tax notice of deficiency, the tax commissioner has to prove that a new fact justifies issuing the notice of deficiency. This is not required for the 1998 capital duty notice of deficiency or the 2001 corporate income tax assessment. It is possible that the Company’s pro rata ownership may lead to the conclusion that there is an exposure for only 50% of the above amounts.

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NRG INTERNATIONAL LLC AND SUBSIDIARIES

     Unasserted Claims and Assessments

     Matra Powerplant Holding B.V. received a statutory notice of deficiency in relation to the corporate income tax assessment for the year 1999. The commissioner did not adjust Matra Powerplant Holding B.V.’s taxable income with the interest deductions relating to the interest-free loans. We assume that this is a clear error given the fact that the tax commissioner already took a different position for the years 1998 and 2001. Settled case law states that if the taxpayer should have been aware of this administrative error the tax commissioner can issue a new statutory notice of deficiency, subject to justifying it by a new fact.

     The unasserted assessment amounts to US $1,283,428.

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.

     The tax commissioner has not yet responded to the Company’s latest response sent to the commission on May 8, 2003.

The threatened respective amounts of capital duty for NRGenerating International B.V.: AUD 1,569,366 (USD $1,243,506) and AUD 3,784,670 (USD $2,998,973). The fine period for seeking prior threatened amounts of capital duty has expired.

     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. has been part of a transaction intended to recapitalize NRGenerating Holdings (No. 4) B.V. The recapitalization was structured in a way to avoid capital duty. The tax commissioner has issued statutory notices of deficiency for both NRGenerating Holdings (No. 4) B.V. and Gunwale B.V., arguing that the transactions were a mere “sham” and that under the abuse of law theory, notwithstanding the exemptions claimed, capital duty should be paid.

     Although formally both the companies are no longer held by the Company since they have been sold in April 2004, under the Share Sale Agreement the Company could still become indirectly liable for the capital duty. The share sale agreement under certain circumstances inter alia grants the buyer a put option in relation to the shares in Gunwale B.V. for a predetermined price.

     Dutch counsel for the buyer of NRGenerating Holdings (No. 4) B.V. and Gunwale B.V. has filed objections against these notices.

     The threatened amounts of capital duty due for 1999 amount to EUR 242,911 for NRGenerating Holdings (No. 4) B.V. and EUR 235,943 for Gunwale B.V. For the year 2000 the threatened amounts of capital duty amount to EUR 1,325,334 for NRGenerating Holdings (No. 4) B.V. and EUR 1,325,334 for Gunwale B.V.

   Matra Powerplant Holding B.V.

     By letter dated September 17, 2004 the tax commissioner responded to a request filed by NRGenerating International B.V., to allocate tax losses to NRGenerating Holdings (No. 4) B.V. upon its departure from the fiscal unity for corporate income tax purposes effective January 1, 2003. The tax commissioner implied that an amount of approximately AUD 140,000,000 of losses should be added to the amount of AUD 377,000,000 which was originally requested by NRGenerating International B.V. By letter dated October 7, 2004 we proposed on behalf of NRGenerating International B.V. to the tax commissioner to limit the tax loss allocation to AUD 377,000,000, as originally requested, on the basis of the fact that the loss allocation forms part of an overall compromise regarding the taxation of NRGenerating International B.V. By letter dated January 14, 2005 the tax commissioner has determined the loss allocation to NRGenerating Holdings (No. 4) B.V. in the amount of AUD 482,154,788.

     The Company believes that it has valid defenses to the legal proceedings, threatened claims, and disputes described above and intends to defend them vigorously. However, these proceedings are inherently subject to many uncertainties. There can be no

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NRG INTERNATIONAL LLC AND SUBSIDIARIES

assurance that additional similar proceedings will not be asserted against the Company or its subsidiaries in the future alleging similar or different theories and seeking similar or different types of damages and relief. Unless specified above, the Company is unable to predict the outcome of these legal proceedings, threatened claims, and disputes may have or reasonably estimate the scope or amount of any associated costs and potential liabilities. An unfavorable outcome in one or more of these proceedings could have a material impact on the Company’s consolidated financial position, results of operations or cash flows.

     Pursuant to the requirements of Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies,” and related guidance, the Company records reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss is reasonably estimable. Management has assessed each of these matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought and the probability of success. Management’s judgment may, as a result of facts arising prior to resolution of these matters or other factors, prove inaccurate and investors should be aware that such judgment is made subject to the known uncertainty of litigation.

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, or 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, or 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, or 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.

     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.

   Gladstone Power Station

     Two of the Company’s wholly-owned, indirect subsidiaries are severally responsible for the prorated payments of principal, interest and related costs incurred in connection with the financing of our equity investment in the unincorporated joint venture Gladstone Power Station. At December 31, 2004, the Company was obligated for the loan of AUD 108.4 million (approximately US$ 84.8 million) in principal. This loan is scheduled to be fully repaid on March 31, 2009.

19. Guarantees

     In November 2002, the FASB issued FASB Interpretation No. 45, or 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 the 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.

     We and our subsidiaries enter into various contracts that include indemnification and guarantee provisions as a routine part of our business activities. Examples of these contracts include asset sale agreements, commodity sale and purchase agreements, joint venture agreements, operations and maintenance agreements, settlement agreements, and other types of contractual agreements with vendors and other third parties. These contracts generally indemnify the counter-party for tax, environmental liability, litigation and other

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NRG INTERNATIONAL LLC AND SUBSIDIARIES

matters, as well as breaches of representations, warranties and covenants set forth in these agreements. In many cases, our maximum potential liability cannot be estimated, since some of the underlying agreements contain no limits on potential liability.

     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 certain of NRG Energy’s current and future restricted subsidiaries (other than certain excluded project subsidiaries, foreign subsidiaries and certain other 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.

     On December 24, 2004, NRG Energy’s credit facility was amended and restated, or the Amended Credit Facility, whereby NRG Energy repaid outstanding amounts and issued a $450.0 million, seven-year senior secured term loan facility, a $350.0 million funded letter of credit facility, and a three-year revolving credit facility in an amount up to $150.0 million. The Amended 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 NRG Energy and certain of NRG’s current and future subsidiaries, including the Company.

     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	$	1,725,000	Obligations under credit Agreement		2013	Nonperformance
NRG Energy Amended and Restated Credit Agreement	$	800,000	Obligations under credit agreement		2011	Nonperformance

     On February 4, 2005, NRG Energy redeemed and retired $375.0 million of Second Priority Notes. As a result of the retirement, the joint and several payment and performance guarantee obligation of the Company was reduced from $1,725.0 million to $1,350.0 million.

20. Sales to Significant Customers

     For the year ended December 31, 2004, the Company derived approximately 92% of its revenues from two customers: Vattenfall Europe A.G. accounted for 42% and NEMMCO accounted for 50%. For the periods December 6, 2003 to December 31, 2003 and January 1, 2003 to December 5, 2003 and for the year ended December 31, 2002, the Company derived approximately 40%, 34% and 31%, respectively, of total revenues from one customer, Vattenfall Europe A.G.

21. Related Party Transactions

     In December 2003, the Company sold 100% of its outstanding shares of Sterling Luxembourg (No. 4) S.a.r.L., or Sterling, which held an interest in Itiquira S.A., Cobee, Flinders Finance and several dormant 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. In December 2004, the note was extinguished by transferring the balance to accounts payable – affiliate. See Note 13 — Capital Leases and Notes Payable — Affiliate.

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NRG INTERNATIONAL LLC AND SUBSIDIARIES

     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, and no gain or loss was recorded in the Company’s statement of operations.

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 Period		For the Period
	Year Ended		December 6 -		January 1 -			Year Ended
	December 31,		December 31,		December 5,			December 31,
	2004		2003		2003			2002
	(In thousands)
Interest paid (net of amounts capitalized)	$	14,425	$	5,590	$	7,711		$	11,899
Income taxes paid/(refunds)		29,059		13,499		(4,278	)		10,597
Detail of businesses and assets acquired:
Current assets (including restricted cash)		—		—		—			2
Fair value of non-current assets		—		—		—			627
Liabilities assumed, including deferred taxes		—		—		—			(218	)
Cash paid net of cash acquired	$	—	$	—	$	—		$	411

23. Subsequent Events

     On April 1, 2005, the Company completed the sale of its 25% interest in Enfield to Infrastructure Alliance Limited, which resulted in net pre-tax proceeds of $59.5 million. A pre-tax gain of approximately $6.0 million will be recorded in the second quarter of 2005 upon completion of the sale. Additionally, the Company expects to receive an additional amount of approximately $2.5 million based upon the post-closing working capital adjustment, which will also be recorded as a pre-tax gain on sale when determinable. The Company was relieved of any future obligations related to its long term gas supply contract with BG Exploration and Production Limited and also was relieved of any future obligations related to the long term debt in the project.

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