EX-99.2

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

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

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.


		/s/ PRICEWATERHOUSECOOPERS LLP

		PricewaterhouseCoopers LLP

Minneapolis, Minnesota
March 10, 2004

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.

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.

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.

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.

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.

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

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.

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.

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

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

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

Period from

For the Year

December 6,

From January 1,

Ended

2003 to

December 31,

December 5,

2004

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

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.

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,

2003

31, 2004

2004

(In thousands of dollars)

Asset retirement obligations

2,623

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

Reporting

2003

(In thousands of dollars)

Asset retirement obligations

396

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.

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

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.

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

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.

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.

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

Period

For the Year

December 6,

January 1,

For the Year

Ended

2003 to

Ended

December 31,

December 5,

December 31,

2004

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

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

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.

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.

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.

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.

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.

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.

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

Period from

For the Year

December 6,

January 1,

For the Year

Ended

2003 to

Ended

December 31,

December 5,

December 31,

2004

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

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.


	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


			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