exv99w5

EX-99.5 10 c87591a1exv99w5.htm FINANCIAL STATEMENTS OF NRG SOUTH CENTRAL GENERATING LLC exv99w5

EXHIBIT 99.5

NRG SOUTH CENTRAL GENERATING LLC

CONSOLIDATED FINANCIAL STATEMENTS

At June 30, 2004 and December 31, 2003, and for

the Three and Six Months Ended June 30, 2004 and 2003

NRG SOUTH CENTRAL GENERATING LLC

INDEX


	Page(s)

Consolidated Financial Statements (Unaudited)
Unaudited Consolidated Balance Sheets at June 30, 2004 and December 31, 2003		2
Unaudited Consolidated Statements of Operations for the three and six months ended June 30, 2004 and 2003		3
Unaudited Consolidated Statements of Members’ Equity for the three and six months ended June 30, 2004 and 2003		4-5
Unaudited Consolidated Statements of Cash Flows for the six months ended June 30, 2004 and 2003		6
Notes to Unaudited Consolidated Financial Statements		7–23

NRG SOUTH CENTRAL GENERATING LLC

CONSOLIDATED BALANCE SHEETS

(Unaudited)



			Reorganized Company

			June 30,		December 31,
			2004		2003


			(In thousands of dollars)
ASSETS
Current assets
	Cash and cash equivalents		$	50,685	$	4,612
	Restricted cash			—		99
	Accounts receivable			33,333		37,080
	Accounts receivable — affiliates			—		3,328
	Notes receivable			—		584
	Inventory			29,797		35,098
	Prepayments and other current assets			4,502		7,079

		Total current assets		118,317		87,880
Property, plant and equipment, net of accumulated depreciation of $34,094 and $2,561, respectively				908,672		914,941
Decommissioning fund investments				4,916		4,809
Intangible assets, net of amortization of $7,314 and $787, respectively				104,290		120,992
Other assets				1,627		3,111

		Total assets	$	1,137,822	$	1,131,733


LIABILITIES AND MEMBERS’ EQUITY
Current liabilities
	Current notes payable — affiliate		$	1,002	$	81,673
	Accounts payable			4,949		10,476
	Accounts payable — affiliates			4,171		—
	Accrued interest — affiliates			10,865		7,434
	Derivative instruments valuation			115		73
	Other current liabilities			15,240		18,452

		Total current liabilities		36,342		118,108
Notes payable — affiliate				79,297		—
Burdensome contracts				330,133		341,004
Other long-term obligations				10,972		9,789

		Total liabilities		456,744		468,901

Commitments and contingencies
Members’ equity				681,078		662,832

		Total liabilities and members’ equity	$	1,137,822	$	1,131,733

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

NRG SOUTH CENTRAL GENERATING LLC

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


		Reorganized			Predecessor			Reorganized			Predecessor
		Company			Company			Company			Company


		Three Months Ended						Six Months Ended

		June 30,			June 30,			June 30,			June 30,
		2004			2003			2004			2003


		(In thousands of dollars)
Revenues		$	102,497		$	92,618		$	197,762		$	196,508

Operating costs			62,649			59,796			122,244			122,245
Depreciation and amortization			14,572			10,006			31,534			18,951
General and administrative expenses			5,897			2,769			10,238			6,094
Reorganization items			(69	)		—			654			—
Restructuring and impairment charges			1,676			2,135			1,676			2,804

	Income from operations		17,772			17,912			31,416			46,414
Other income, net			17			546			102			934
Interest expense			(1,296	)		(19,547	)		(3,646	)		(38,489	)

	Income (loss) before income taxes		16,493			(1,089	)		27,872			8,859
Income tax expense			5,596			—			10,175			—

	Net income (loss)	$	10,897		$	(1,089	)	$	17,697		$	8,859

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

NRG SOUTH CENTRAL GENERATING LLC

CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY

Three Months Ended June 30, 2004 and 2003

(Unaudited)



	Members’				Members’		Accumulated			Total
					Contributions/		Net Income			Members’
	Units		Amount		Distributions		(Loss)			Equity


	(In thousands of dollars)
Balances at March 31, 2003 (Predecessor Company)		1,000	$	1	$	434,161	$	(100,564	)	$	333,598
Net loss and comprehensive loss		—		—		—		(1,089	)		(1,089	)

Balances at June 30, 2003 (Predecessor Company)		1,000	$	1	$	434,161	$	(101,653	)	$	332,509

Balances at March 31, 2004 (Reorganized Company)		1,000	$	1	$	662,538	$	7,093		$	669,632
Contribution from members		—		—		549		—			549
Net income and comprehensive income		—		—		—		10,897			10,897

Balances at June 30, 2004 (Reorganized Company)		1,000	$	1	$	663,087	$	17,990		$	681,078

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

NRG SOUTH CENTRAL GENERATING LLC

CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY

Six Months Ended June 30, 2004 and 2003

(Unaudited)



	Members’				Members’		Accumulated			Total
					Contributions/		Net Income			Members’
	Units		Amount		Distributions		(Loss)			Equity


	(In thousands of dollars)
Balances at December 31, 2002 (Predecessor Company)		1,000	$	1	$	434,161	$	(110,512	)	$	323,650
Net income and comprehensive income		—		—		—		8,859			8,859

Balances at June 30, 2003 (Predecessor Company)		1,000	$	1	$	434,161	$	(101,653	)	$	332,509

Balances at December 31, 2003 (Reorganized Company)		1,000	$	1	$	662,538	$	293		$	662,832
Contribution from members		—		—		549		—			549
Net income and comprehensive income		—		—		—		17,697			17,697

Balances at June 30, 2004 (Reorganized Company)		1,000	$	1	$	663,087	$	17,990		$	681,078

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

NRG SOUTH CENTRAL GENERATING LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


				Reorganized			Predecessor
				Company			Company

				Six Months			Six Months
				Ended			Ended
				June 30,			June 30,
				2004			2003


				(In thousands of dollars)
Cash flows from operating activities
Net income				$	17,697		$	8,859
Adjustments to reconcile net income to net cash provided by operating activities
	Depreciation and amortization				31,533			18,951
	Amortization of out-of-market power contracts				(10,871	)		—
	Amortization of intangibles				6,527			—
	Impairment charges				1,676			—
	Amortization of debt discount				1,265			—
	Amortization of debt issuance costs				—			837
	Unrealized (gain) loss on derivatives				42			(423	)
	Deferred income taxes				10,175			—
	Changes in assets and liabilities
		Accounts receivable			3,747			15,621
		Inventory			5,301			4,006
		Prepayments and other current assets			2,577			(4,407	)
		Accounts payable			(5,527	)		12,634
		Accounts payable and receivable — affiliates			7,499			1,307
		Accrued interest — affiliates			3,431			(32,528	)
		Accrued fuel and purchase power expense			—			(7,501	)
		Other current liabilities			(3,212	)		(3,798	)
		Changes in other assets and liabilities			2,560			(63	)

			Net cash provided by operating activities		74,420			13,495

Cash flows from investing activities
Capital expenditures					(26,940	)		(5,389	)
Decrease in notes receivable					584			1,500
(Increase)/decrease in restricted cash					99			(1,917	)

			Net cash used in investing activities		(26,257	)		(5,806	)

Cash flows from financing activities
Contribution by members					549			—
Payment of intercompany loan					(2,639	)		—
Checks in excess of cash					—			42

			Net cash provided by (used in) financing activities		(2,090	)		42

			Net change in cash and cash equivalents		46,073			7,731
Cash and cash equivalents
Beginning of period					4,612			310

End of period				$	50,685		$	8,041

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

NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)


1.	Organization

NRG South Central Generating LLC (“NRG South Central” or the “Company”) was formed in 2000 and is an indirect wholly owned subsidiary of NRG Energy, Inc. (“NRG Energy”). NRG South Central owns 100% of Louisiana Generating LLC (“Louisiana Generating”), NRG New Roads Holding LLC (“New Roads”), NRG Sterlington Power LLC (“Sterlington”), Big Cajun I Peaking Power LLC (“Big Cajun Peaking”) and NRG Bayou Cove LLC (“Bayou Cove”). NRG South Central’s members are NRG Central U.S. LLC (“NRG Central”) and South Central Generation Holding LLC (“South Central Generation”). NRG Central and South Central Generation are directly held wholly owned subsidiaries of NRG Energy, each of which owns a 50% interest in NRG South Central.

NRG South Central was formed for the purpose of financing, acquiring, owning, operating and maintaining through its subsidiaries and affiliates the facilities owned by Louisiana Generating and any other facilities that it or its subsidiaries may acquire in the future.

Pursuant to a competitive bidding process, following the Chapter 11 bankruptcy proceeding of Cajun Electric Power Cooperative, Inc. (“Cajun Electric”), Louisiana Generating acquired the non-nuclear electric power generating assets of Cajun Electric. New Roads was formed for the purpose of holding assets that Louisiana Generating acquired from Cajun Electric which are not necessary for the operation of the newly acquired generating facilities and, with respect to some of these assets, may not be held by Louisiana Generating under applicable federal regulations. Sterlington, which was acquired by NRG Energy and contributed to NRG South Central in August 2000, was formed for the purpose of developing, constructing, owning, and operating an approximately 200 MW simple cycle gas peaking facility in Sterlington, Louisiana. Louisiana Generating purchases the capacity and is entitled to all energy from Sterlington. Big Cajun Peaking was formed to develop, construct and own a 238 MW gas-fired peaking generating facility located in New Roads, Louisiana. Bayou Cove was formed to develop, construct and own a 320 MW gas-fired peaking generating facility located in Jennings, Louisiana. Bayou Cove is operated as a merchant power facility.

On March 31, 2000, for approximately $1,055.9 million, Louisiana Generating acquired 1,708 MW of electric power generation facilities located in New Roads, Louisiana (“Cajun facilities”). The acquisition was financed through a combination of project level long-term debt issued by NRG South Central and equity contributions from NRG South Central’s members. Prior to December 23, 2003, Louisiana Generating was a guarantor of the bonds issued on March 30, 2000, to acquire the Cajun facilities. The acquisition was accounted for under the purchase method of accounting with the aggregate purchase price allocated among the acquired assets and liabilities assumed.

Pursuant to a project development agreement between NRG Energy and Koch Power, Inc., NRG Energy agreed in April 1999 to participate in the development of an approximately 200 MW simple cycle gas peaking facility in Sterlington, Louisiana. Development of the facility had been commenced by Koch Power’s affiliate, Koch Power Louisiana LLC, a Delaware limited liability company. In August 2000, NRG Energy acquired 100% of Koch Power Louisiana from Koch Power, and renamed it NRG Sterlington Power LLC and contributed the subsidiary to NRG South Central. In August, 2001, the facility became commercially operational.

Big Cajun I Peaking Power LLC was formed in July 2000 for the purpose of developing, owning and operating an approximately 238 MW simple cycle natural gas peaking facility expansion project at the Big Cajun I site in New Roads, Louisiana. The peaking facility was completed in June 2001. The energy and capacity generated by the expansion project is used to help meet Louisiana Generating’s obligations under the Cajun facilities’ power purchase agreements, with any excess power and capacity being marketed by NRG Power Marketing.

NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

During November 2000, NRG Energy acquired a 49% limited partnership interest and a 1% general partnership interest in SRW Cogeneration Limited Partnership (“SRW Cogeneration”) for $15 million and contributed the partnership interests to NRG Sabine River Works LP LLC and NRG Sabine River Works GP LLC, Delaware limited liability companies wholly owned by NRG South Central. SRW Cogeneration completed the facility which became commercially operational in November 2001. The approximately 450 MW natural gas-fired cogeneration plant is located at the DuPont Company’s Sabine River Works petrochemical facility near Orange, Texas. Subsidiaries of Conoco, Inc. own the other 49% and 1% general partnership interests in SRW Cogeneration. On November 5, 2002, the investment in SRW Cogeneration was sold to Conoco, Inc for a nominal value and the assumption of certain outstanding obligations.

NRG Bayou Cove LLC was formed in September 2001 for the purpose of developing, owning and operating an approximately 320 MW gas-fired peaking generating facility located near Jennings, Louisiana.


	*Recent Developments*

On May 14, 2003, NRG Energy and 25 of its direct and indirect wholly owned subsidiaries commenced voluntary petitions under Chapter 11 of the bankruptcy code in the United States Bankruptcy Court for the Southern District of New York. The Company and its direct subsidiaries were included in the Chapter 11 filing. During the bankruptcy proceedings, NRG Energy continued to conduct business and manage the companies as debtors in possession pursuant to sections 1107(a) and 1108 of the bankruptcy code. Two plans of reorganization were filed in connection with the restructuring efforts. The first, filed on May 14, 2003, and referred to as NRG Energy’s Plan of Reorganization, relates to NRG Energy and the other NRG Energy plan debtors. The second plan, relating to the Company, the Northeast Generating subsidiaries and the other South Central subsidiaries, referred to as the Northeast/ South Central Plan of Reorganization, was filed on September 17, 2003. On November 24, 2003, the bankruptcy court entered an order confirming NRG Energy’s Plan of Reorganization and the plan became effective on December 5, 2003. On November 25, 2003, the bankruptcy court issued an order confirming the Northeast/ South Central Plan of Reorganization and the plan became effective on December 23, 2003. In connection with NRG Energy’s emergence from bankruptcy, NRG Energy, adopted fresh start accounting in accordance with AICPA Statement of Position 90-7, Financial Reporting by Entities in Reorganization Under the Bankruptcy Code (“SOP 90-7”) on December 5, 2003. NRG Energy’s fresh start accounting was applied to the Company on a push down accounting basis with the financial statement impact recorded as an adjustment to the December 6, 2003 members’ equity.


	*Northeast/ South Central Plan of Reorganization*

The Northeast/ South Central Plan of Reorganization was proposed on September 17, 2003 after necessary financing commitments were secured. On November 25, 2003, the bankruptcy court issued an order confirming the Northeast/ South Central Plan of Reorganization and the plan became effective on December 23, 2003. In connection with the order confirming the Northeast/ South Central Plan of Reorganization, the court entered a separate order which provides that the allowed amount of the bondholders’ claims shall equal in the aggregate the sum of (i) $1.3 billion plus (ii) any accrued and unpaid interest at the applicable contract rates through the date of payment to the indenture trustee plus (iii) the reasonable fees, costs or expenses of the collateral agent and indenture trustee (other than reasonable professional fees incurred from October 1, 2003) plus (iv) $19.6 million, ratably, for each holder of bonds based upon the current outstanding principal amount of the bonds and irrespective of (a) the date of maturity of the bonds, (b) the interest rate applicable to such bonds and (c) the issuer of the bonds.

The creditors of Northeast and South Central subsidiaries were unimpaired by the Northeast/ South Central Plan of Reorganization. The creditors holding allowed general secured claims were paid in cash, in full on the effective date of the Northeast/ South Central Plan of Reorganization. Holders of allowed unsecured claims have received either (i) cash equal to the unpaid portion of their allowed unsecured claim,

NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(ii) treatment that leaves unaltered the legal, equitable and contractual rights to which such unsecured claim entitles the holder of such claim, (iii) treatment that otherwise renders such unsecured claim unimpaired pursuant to section 1124 of the bankruptcy code or (iv) such other, less favorable treatment that is confirmed in writing as being acceptable to such holder and to the applicable debtor.


2.	Summary of Significant Accounting Policies


	*Basis of Presentation*

As used in these unaudited interim consolidated financial statements, “Predecessor Company” refers to the Company prior to NRG Energy’s emergence from bankruptcy. “Reorganized Company” refers to the Company after NRG Energy’s emergence from bankruptcy.

The accompanying unaudited interim consolidated financial statements have been prepared in accordance with the Securities and Exchange Commission’s or “SEC” regulations for interim financial information. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. The accounting policies followed are set forth in Note 2 to the Company’s annual audited consolidated financial statements for the year ended December 31, 2003. The following notes should be read in conjunction with such policies and other disclosures. Interim results are not necessarily indicative of results for a full year.

In the opinion of management, the accompanying unaudited interim consolidated financial statements contain all material adjustments necessary to present fairly the Company’s consolidated financial position as of June 30, 2004 and December 31, 2003, the results of its operations and members’ equity for the three and six months ended June 30, 2004 and 2003 and the cash flows for the six months ended June 30, 2004 and 2003. Certain prior-year amounts have been reclassified for comparative purposes.


	*Comparability of Financial Information*

Due to NRG Energy’s adoption of Fresh Start as of December 5, 2003, the Reorganized Company’s consolidated balance sheet, statement of operations and statement of cash flows have not been prepared on a consistent basis with the Predecessor Company’s financial statements and are not comparable in certain respects to the financial statements prior to the application of push down accounting from NRG Energy’s fresh start accounting. A black line has been drawn on the accompanying consolidated financial statements (excluding the consolidated balance sheet) to separate and distinguish between the Reorganized Company and the Predecessor Company.


3.	Other Charges

Reorganization items and restructuring and impairment charges included in operating costs and expenses in the consolidated statements of operations include the following:

Reorganized

Predecessor

Reorganized

Predecessor

Company

Three Months

Six Months

Ended

June 30,

2004

2003

2004

2003

(In thousands of dollars)

Reorganization items

(69

)

—

654

—

Restructuring and impairment charges

1,676

2,135

1,676

2,804

1,607

2,135

2,330

2,804

NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the six months ended June 30, 2004, the Company incurred $0.7 million of reorganization costs. All reorganization costs have been incurred since the Company filed for bankruptcy in May 2003. These costs consist of bankruptcy related charges primarily related to professional fees and liability settlements. For the three months ended June 30, 2004, a net credit of $69,000 was recorded related to the settlement of obligations recorded under Fresh Start accounting. No reorganization costs were recorded for the three and six months ended June 30, 2003.

The Company incurred total restructuring charges of approximately $2.1 million and $2.8 million, respectively, for the three and six months ended June 30, 2003. These costs consist of advisor fees. All amounts were paid during the first half of 2003.

The Company periodically reviews the recoverability of its long-lived assets in accordance with the guidelines of Statement of Financial Accounting Standards (“SFAS”) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (“SFAS 144”). In the second quarter of 2004, the Company made the decision to sell a turbine, whose carrying value was more than the sales price. Therefore, the Company recorded $1.7 million in impairment charges for the three and six months ended June 30, 2004. No impairment charges were recorded for the three and six months ended June 30, 2003.


4.	Inventory

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



		Reorganized Company

		June 30,		December 31,
		2004		2003


		(In thousands of dollars)
Coal		$	20,915	$	26,108
Spare parts			8,078		8,207
Fuel oil/gas			804		783

	Total inventory	$	29,797	$	35,098


5.	Property, Plant and Equipment

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



	Reorganized Company

	June 30,			December 31,
	2004			2003


	(In thousands of dollars)
Land	$	30,935		$	30,935
Facilities, machinery and equipment		885,655			885,656
Office furnishings and equipment		582			582
Construction in progress		25,594			329
Accumulated depreciation		(34,094	)		(2,561	)

Property, plant and equipment, net	$	908,672		$	914,941


6.	Asset Retirement Obligation

Effective January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“SFAS No. 143”). SFAS No. 143 requires an entity to recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred. Upon initial recognition of a liability for an asset retirement obligation, an entity shall capitalize an asset

NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes and written or oral contracts, including obligations arising under the doctrine of promissory estoppel.

The Company identified certain retirement obligations within its operations. These asset retirement obligations are related primarily to the future dismantlement of equipment on leased property and environment obligations related to ash disposal site closures. The Company also identified similar other asset retirement obligations that could not be calculated because the assets associated with the retirement obligations were determined to have an indeterminate life. The adoption of SFAS No. 143 resulted in recording a $0.3 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 as the Company considered the cumulative effect to be immaterial.

The following represents the balances of the asset retirement obligation at January 1, 2004, and the accretion of the asset retirement obligation for the six months ended June 30, 2004, which is included in other long-term obligations in the consolidated balance sheets.

Reorganized Company

Accretion

for the

Beginning

Six Months

Ending

Balance

Ended

Balance

January 1,

June 30,

2004

(In thousands of dollars)

Asset retirement obligations

2,638

2,728


7.	Intangible Assets

Upon the 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 to resemble the Company’s realization of such assets.

Power sale agreements will be amortized as a reduction to revenue over the terms and conditions of each contract. The remaining amortization period is three years for the power sale agreements. Emission allowances will be amortized as additional fuel expense based upon the actual level of emissions from the respective plants through 2023. Aggregate amortization recognized for the three and six months ended June 30, 2004, was approximately $3.2 million and $6.5 million, respectively. The annual aggregate amortization for each of the five succeeding years is expected to approximate $11.5 million in years one through three and $5.0 million in years four and five for both the power sale 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 three and six months ended June 30, 2004, the Company reduced its tax valuation allowance by $5.6 million and $10.2 million, respectively, 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 allowances should first reduce intangible assets until exhausted, and thereafter be recorded as a direct addition to paid in capital.

NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Intangible assets consisted of the following:


	Power Sale			Emission
	Agreements			Allowances			Total


	(In thousands of dollars)
Balances as of December 31, 2003	$	27,013		$	93,979		$	120,992
Tax valuation adjustment		(2,271	)		(7,904	)		(10,175	)
Amortization		(3,636	)		(2,891	)		(6,527	)

Balances as of June 30, 2004	$	21,106		$	83,184		$	104,290


8.	Notes Payable — Affiliate

NRG South Central’s long-term debt consists of the following:



		Reorganized Company

		June 30,			December 31,
		2004			2003


		(In thousands of dollars)
NRG Peaker — Bayou Cove — note payable affiliate due 2019 — 6.673%		$	102,852		$	105,491
Unamortized fair value adjustment			(22,553	)		(23,818	)

	Subtotal		80,299			81,673
Less current maturities			1,002			81,673

	Total	$	79,297		$	—


	*Project Level Debt*

On June 18, 2002, NRG Peaker Finance Company LLC (“NRG Peaker”), a wholly owned subsidiary of NRG Energy and an affiliate of the Company, issued $325 million of senior secured bonds. The bonds bear interest at a floating rate equal to three months USD-LIBOR BBA plus 1.07%. Interest on the bonds is payable on March 10, June 10, September 10, and December 10 of each year commencing on September 10, 2002. The Peaker projects which secure the senior secured bonds are a combination of several indirect wholly owned subsidiaries of NRG Energy, which include the following entities: Bayou Cove Peaking Power LLC (“Bayou Cove”), Big Cajun I Peaking Power LLC (“Big Cajun Peaking”), NRG Rockford LLC, Rockford II LLC and NRG Sterlington Power LLC (“Sterlington”). Three of these entities, Bayou Cove, Big Cajun Peaking and Sterlington, are wholly owned nonguarantor subsidiaries of the Company. NRG Peaker Finance Company LLC advanced unsecured loans in the amounts of $107.4 million to Bayou Cove through project loan agreements. The project owners used the gross proceeds of the loans to (1) reimburse NRG Energy for construction and/or acquisition costs for the peaker projects previously paid by NRG Energy, (2) pay to XL Capital Assurance (“XLCA”) the premium for the Bond Policy, (3) provide funds to NRG Peaker to collateralize a portion of NRG Energy’s contingent guaranty obligations and (4) pay transaction costs incurred in connection with the offering of the bonds (including reimbursement of NRG Energy for the portion of such costs previously paid by NRG Energy). At June 30, 2004 and December 31, 2003, Bayou Cove had an affiliate loan outstanding in the amount of $102.9 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.

The bonds are secured by a pledge of membership interests in NRG Peaker and a security interest in all of its assets, which initially consisted of notes evidencing loans to the affiliate project owners, including Bayou Cove, Big Cajun Peaking and Sterlington. The project owners’ jointly and severally guarantied the entire principal amount of the bonds and interest on such principal amount. The project owner guaranties are secured by a pledge of the membership interest in three of five project owners, including Bayou Cove, and a

NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

security interest in substantially all of the project owners’ assets (“the peaker projects”), including equipment, real property rights, contracts and permits. NRG Energy has entered into a contingent guaranty agreement in favor of the collateral agent for the benefit of the secured parties, under which it agreed to make payments to cover scheduled principal and interest payments on the bonds and regularly scheduled payments under the interest rate swap agreement, to the extent that the net revenues from the peaker projects are insufficient to make such payments, in specified circumstances. This financing contains a cross-default provision related to the failure by NRG Energy to make payment of principal, interest or other amounts due on debt for borrowed money in excess of $50 million of payment defaults by NRG Energy, a covenant that was violated in October 2002. In addition, liens were placed against the Bayou Cove facility resulting in an additional default. NRG Peaker is in the process of getting such liens released. On October 22, 2002, XLCA issued a notice of default on the NRG Peaker financing facility. On December 10, 2002, $16.0 million in interest, principal and swap payments were made from NRG Energy’s restricted cash accounts. As a result, $319.4 million in principal remains outstanding as of December 31, 2002. On May 12, 2003, XLCA accelerated the bonds, rendering the bonds immediately due and payable. Also on May 12, 2003, a forbearance agreement was entered into which forbears XLCA from exercising its rights and remedies.

On December 10, 2003, $31.1 million in interest, principal and swap payments were made from restricted cash accounts. As a result, $311.4 million in principal remains outstanding as of December 31, 2003.

On January 6, 2004, NRG Energy and XLCA consummated a comprehensive restructuring arrangement which provides for, among other things, the provision of a letter of credit by NRG Energy for the benefit of the secured parties in the NRG Peaker financing in lieu of the contingent guarantee described above, the cure or waiver of all defaults under the original financing agreement and the mutual release of claims by the parties. With the exception of distributions to pay taxes, distributions to equity holders are subject to tests regarding NRG Peaker reserve funding and financial ratios. At June 30, 2004, NRG Peaker was not in default under its financing agreements; therefore, Bayou Cove’s debt has been reclassified to long-term.

In connection with the revaluation of NRG Peaker’s debt to fair value under SOP 90-7, debt discounts were recorded in debt. At June 30, 2004 and December 31, 2003, the unamortized debt discounts recorded in debt were $68.3 million and $72.1 million, respectively. Approximately $22.6 million and $23.8 million of these amounts relate to Bayou Cove at June 30, 2004 and December 31, 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% 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 project owners’ guarantees. Net payments to be made by NRG Peaker under the interest rate swap agreement will be guaranteed pursuant to a separate financial guaranty insurance policy with XLCA, the issuer of which will have a security interest in the collateral for the bonds and the collateral for the project owners’ guaranties. NRG Peaker was in compliance with this agreement at December 31, 2003. The agreement expires in June 2019.


9.	Derivative Instruments and Hedging Activity

SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS No. 133”), as amended, requires the Company to record all derivatives on the consolidated balance sheet as assets or liabilities at fair value. For derivatives designated as cash flow hedges, the effective portion of the changes in fair value of the derivatives are recorded in accumulated other comprehensive income (“OCI”) and subsequently recognized in earnings when the hedged items impact 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. Changes in the fair value of nonhedge derivatives will be immediately

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

recognized in earnings. Additionally, many of the Company’s sales and purchase agreements qualify as normal purchases and sales under SFAS No. 133, and are therefor exempt from fair value accounting treatment.

SFAS No. 133 applies to the Company’s long-term power sales contracts, long-term fuel purchase contracts and other energy related commodities financial instruments used to mitigate variability in earnings due to fluctuations in spot market prices, hedge fuel requirements at generation facilities and protect investments in fuel inventories. At June 30, 2004, the Company had various commodity contracts extending through 2005. None of these contracts are designated as hedging instruments.

The Company has no derivative instruments classified as hedges and no deferred gains or losses in OCI at June 30, 2004 and December 31, 2003.


	*Statement of Operations*

The following table summarizes the pre-tax effects of nonhedge derivatives on the Company’s consolidated statements of operations for the three and six months ended:

Reorganized

Predecessor

Reorganized

Predecessor

Company

Three Months

Six Months

Ended

June 30,

2004

2003

2004

2003

(In thousands of dollars)

Revenues

393

203

420

Cost of operations

—

144

—

Total statement of operations impact before tax

393

347

423

During the three and six months ended June 30, 2004 and 2003, the Company recognized no gain or loss due to the ineffectiveness of commodity cash flow hedges, and no components of NRG South Central’s derivative instruments gains or losses were excluded from the assessment of effectiveness.

The Company’s earnings for the three months ended June 30, 2004 and 2003, were increased by $0.4 million and $0.4 million, respectively and for the six months ended June 30, 2004 and 2003, the Company’s earnings increased by $42,000 and $0.4 million, respectively associated with the changes in fair value of energy related derivative instruments not accounted for as hedges in accordance with SFAS No. 133.


10.	Commitments and Contingencies


	*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 the application of push down accounting, certain of Louisiana Generating’s long-term power supply agreements were determined to be at above or below market rates. As a result, the Company valued these agreements and recognized the fair value of such contracts on the December 6, 2003 balance sheet. The fair value of these contracts that were deemed to be valuable have been included in intangible assets. The fair value of contracts determined to be significantly burdensome were recorded as noncurrent liabilities. The favorable and unfavorable contract valuation amounts will be amortized as a net increase to revenues over the terms and conditions of each contract. These contracts consist primarily of the long-term power sale agreements Louisiana Generating has with its cooperative

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

customers and certain others. The gross carrying amount of the unfavorable out-of-market power sales agreements at both June 30, 2004 and December 31, 2003, was $342.2 million. During the three and six months ended June 30, 2004, approximately $3.5 million and $6.7 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.

Louisiana Generating must contract for all transmission service 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.

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 have selected the first option which is a fixed fee through 2004 and determined using a formula which is based on gas prices and the cost of delivered coal for the period thereafter. At the end of the fifteenth year of the contract, the cooperatives may switch to the second fuel option. The second fuel option consists of a pass-through of fuel costs, with a guaranteed coal heat rate and purchased energy costs, excluding the demand component in purchased power. From time to time, Louisiana Generating may offer fixed fuel rates which the cooperative may elect to utilize. The variable operation and maintenance charge is fixed through 2004 and escalates at either approximately 3% per annum or in accordance with actual changes in specified indices as selected by the distribution cooperative. Five of the distribution cooperatives elected the fixed escalation provision and one elected the specified indices provision.

The Form A agreement also contains provisions for special rates for certain customers based on the economic development benefits the customer will provide and other rates to improve the distribution cooperative’s ability to compete with service offered by political subdivisions.


	Form B Agreements

One distribution cooperative selected the Form B Power Supply Agreement. The term of the Form B power supply agreement commences on March 31, 2000 and ends on December 31, 2024. The Form B power supply agreement allows the distribution cooperative the right to elect to limit its purchase obligations to “base supply” or also to purchase “supplemental supply.” Base supply is the distribution cooperative’s ratable share of the generating capacity purchased by Louisiana Generating from Cajun Electric. Supplemental supply is

NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 its customers.

For base supply, Louisiana Generating charges the distribution cooperative a demand charge, an energy charge and a fuel charge. The demand charge for each contract year is set forth in the agreement and is subject to increase for environmental legislation or occupational safety and health laws enacted after the effective date of the agreement. Louisiana Generating can increase the demand charge to the extent its cost of providing supplemental supply exceeds $400 per kilowatt (“kW”). The energy charge is fixed through 2004, and decreased slightly for the remainder of the contract term. The fuel charge is a pass-through of fuel and purchased energy costs. The distribution cooperative may elect to be charged based on a guaranteed coal-fired heat rate of 10,600 British Thermal Units per kilowatt-hour (“Btu/kWh”), and it may also select fixed fuel factors as set forth in the agreement for each year through 2008. The one distribution cooperative which selected this form of agreement elected to utilize the fixed fuel factors. For the years after 2008, Louisiana Generating will offer additional fixed fuel factors for five-year periods that may be elected. For the years after 2008, the distribution cooperative may also elect to have its charges computed under the pass-through provisions with or without the guaranteed coal-fired heat rate.

At the beginning of year six, Louisiana Generating will establish a rate fund equal to the ratable share of $18 million. The amount of the fund will be approximately $720,000. This fund will be used to offset the energy costs of the Form B distribution cooperatives which elected the fuel pass-through provision of the fuel charge, to the extent the cost of power exceeds $0.04/kWh. Any funds remaining at the end of the term of the power supply agreement will be returned to Louisiana Generating.


	Form C Agreements

Four distribution cooperatives selected the Form C power supply agreement. The Form C power supply agreement is identical to the Form A power supply agreement, except for the following.

The term of the Form C power supply agreement was for four years following the closing date of the acquisition of the Cajun facilities. In October 2003, the Louisiana Public Service Commission approved contract extensions for all four Form C distribution cooperatives for terms of an additional five or ten years.

Louisiana Generating will charge the distribution cooperative a demand rate, a variable operation and maintenance charge and 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.

NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 (“SWEPCO”), one agreement with South Mississippi Electric Power Association (“SMEPA”) and one agreement with Municipal Energy Agency of Mississippi (“MEAM”).

The SWEPCO Operating Reserves and Off-Peak Power Sale Agreement terminates on December 31, 2007. The agreement requires Louisiana Generating to supply 100 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.

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 increased 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.

NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Coal Supply Agreement

Louisiana Generating has entered into a coal supply agreement with Triton Coal. The coal is primarily sourced from Triton Coal’s Buckskin and North Rochelle mines located in the Powder River Basin, Wyoming. The initial term of the coal supply agreement ends on March 31, 2005. The agreement establishes a base price per ton for coal supplied by Triton Coal. The base price is subject to adjustment for changes in the level of taxes or other government fees and charges, variations in the caloric value and sulfur content of the coal shipped, and changes in the price of SO(2) emission allowances. The base price is based on certain annual weighted average quality specifications, subject to suspension and rejection limits.


	Coal Transportation Agreement

Louisiana Generating entered into a coal transportation agreement with Burlington Northern and Santa Fe Railway and American Commercial Terminal. The term of the agreement is five years from March 31, 2000. This agreement provides for the transportation of all of the coal requirements of Big Cajun II from the mines in Wyoming to Big Cajun II.


	Transmission and Interconnection Agreements

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, Inc., Entergy Louisiana, Inc., Entergy Mississippi, Inc., and Entergy New Orleans, Inc. Louisiana Generating also entered into two interconnection and operating agreements with Entergy Gulf States, Inc. on May 1, 2002. The Cajun facilities are connected to the transmission system of Entergy Gulf States, 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.


	*Environmental Matters*

The construction and operation of power projects are subject to stringent environmental and safety protection and land use laws and regulation in the United States. These laws and regulations generally require lengthy and complex processes to obtain licenses, permits and approvals from federal, state and local agencies. If such laws and regulations become more stringent and the Company’s facilities are not exempted from coverage, the Company could be required to make extensive modifications to further reduce potential environmental impacts. Also, the Company could be held responsible under environmental and safety laws for the cleanup of pollutant releases at its facilities or at off-site locations where it has sent wastes.

The Company and its subsidiaries strive to exceed the standards of compliance with applicable environmental and safety regulations. Nonetheless, the Company expects that future liability under or compliance with environmental and safety requirements could have a material effect on its operations or competitive position. It is not possible at this time to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of possible changes to environmental and safety regulations, regulatory interpretations or enforcement policies. In general, the effect of future laws or regulations is expected to require the addition of pollution control equipment or the imposition of restrictions on the Company’s operations.

The Company establishes accruals where reasonable estimates of probable environmental and safety liabilities are possible. The Company adjusts the accruals when new remediation responsibilities are discovered and probable costs become estimable, or when current remediation estimates are adjusted to reflect new information.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Under various federal, state and local environmental laws and regulations, a current or previous owner or operator of any facility, including an electric generating facility, may be required to investigate and remediate releases or threatened releases of hazardous or toxic substances or petroleum products located at the facility, and may be held liable to a governmental entity or to third parties for property damage, personal injury and investigation and remediation costs incurred by the party in connection with any releases or threatened releases. These laws, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended by the Superfund Amendments and Reauthorization Act of 1986, impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and courts have interpreted liability under such laws to be strict (without fault) and joint and several. The cost of investigation, remediation or removal of any hazardous or toxic substances or petroleum products could be substantial. The Company has not been named as a potentially responsible party with respect to any off-site waste disposal matter.

Liabilities associated with closure, post-closure care and monitoring of the ash ponds owned and operated on site at the Big Cajun II Generating Station are addressed through the use of a trust fund maintained by the Company (one of the instruments allowed by the Louisiana Department of Environmental Quality for providing financial assurance for expenses associated with closure and post-closure care of the ponds). The value of the trust fund is approximately $4.9 million at June 30, 2004, and the Company is making annual payments to the fund in the amount of about $116,000. See Note 13.

The Louisiana Department of Environmental Quality has promulgated State Implementation Plan revisions to bring the Baton Rouge ozone nonattainment area into compliance with National Ambient Air Quality Standards. The Company participated in development of the revisions, which require the reduction of NO(x) emissions at the gas-fired Big Cajun I Power Station and coal-fired Big Cajun II Power Station to 0.1 pounds NO(x) per million Btu heat input and 0.21 pounds NO(x) per million Btu heat input, respectively. This revision of the Louisiana air rules would appear to constitute a change-in-law covered by agreement between Louisiana Generating LLC and the electric cooperatives allowing the costs of added combustion controls to be passed through to the cooperatives. The capital cost of combustion controls required at the Big Cajun II Generating Station to meet the State’s NO(x) regulations will total about $10.0 million for Unit 1. Units 2 and 3 have already made such changes. The capital cost of combustion controls required at the Big Cajun I Generating Station to meet the State’s NO(x) regulations will total about $5 million to $10 million for the Unit 1 and 2 steam boilers.


	*Legal Issues*


	United States Environmental Protection Agency Request for Information under Section 114 of the Clean Air Act

On January 27, 2004, Louisiana Generating, LLC and Big Cajun II received a request for information under Section 114 of the Clean Air Act from the United States Environmental Protection Agency (“EPA”) seeking information primarily relating to physical changes made at Big Cajun II in 1994 and 1995 by the predecessor owner of that facility. Louisiana Generating, LLC and Big Cajun II have been responding to the EPA request in an appropriate manner. At the present time, the Company cannot predict the probable outcome in this matter.


	Travis Ballou, et al. v. Ralph Mabey, et al., United States Court of Appeals for the Fifth Circuit, No. 03-30343; Kenneth W. Austin, et al. v. Ralph Mabey, et al., United States District Court for the Middle District of Louisiana, Civil Action No. 00-728-D-M1

Two lawsuits are pending in Federal Court involving 39 former employees of Cajun Electric Power Cooperative, Inc. who claim age/race/sex discrimination in failure to hire by Louisiana Generating. One

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

lawsuit was dismissed on summary judgment and has been appealed. In the remaining lawsuit, the Company is awaiting the District Court’s ruling on Louisiana Generating’s motions for summary judgment.


	In the Matter of Louisiana Generating, LLC, Adversary Proceeding No. 2002-1095 1-EQ on the Docket of the Louisiana Division of Administrative Law

During 2000, the Louisiana Department of Environmental Quality (“DEQ”) issued a Part 70 Air Permit modification to Louisiana Generating to construct and operate two 240 MW natural gas-fired turbines. The Part 70 Air Permit set emissions limits for the criteria air pollutants, including NO(x), based on the application of Best Available Control Technology (“BACT”). The BACT limitation for NO(x) was based on the guarantees of the manufacturer, Siemens-Westinghouse. Louisiana Generating sought an interim emissions limit to allow Siemens-Westinghouse time to install additional control equipment. To establish the interim limit, DEQ issued a Compliance Order and Notice of Potential Penalty, No. AE-CN-02-0022, on September 8, 2002, which is, in part, subject to the referenced administrative hearing. DEQ alleged that Louisiana Generating did not meet its NO(x) emissions limit on certain days, did not conduct all opacity monitoring and did not complete all record keeping and certification requirements. Louisiana Generating intends to vigorously defend certain claims and any future penalty assessment, while also seeking an amendment of its limit for NO(x). An initial status conference was held with the Administrative Law Judge and quarterly reports are being submitted to that judge to describe progress, including settlement and amendment of the limit. In late February 2004, the Company timely submitted to the DEQ an amended BACT analysis and amended Prevention of Significant Deterioration and Title V permit application to amend the NO(x) limit. The DEQ is presently processing the permit application. In addition, Louisiana Generating may assert breach of warranty claims against the manufacturer. With respect to the administrative action described above, at this time the Company is unable to predict the eventual outcome of this matter or the potential loss contingencies, if any, to which the Company may be subject.


11.	Regulatory Issues

The Company’s assets are located within the control area of Entergy Corporation (“Entergy”), a vertically integrated utility. The utility performs the scheduling, reserve and reliability functions that are administered by the ISOs in certain other regions of the United States and Canada. The Company operates a National Electric Reliability Council (“NERC”) certified control area within the Entergy control area, which is comprised of the Company’s generating assets and its co-op customer loads. Although the reliability functions performed are essentially the same, the primary differences between these markets lie principally in the physical delivery and price discovery mechanisms. In the South Central region, all power sales and purchases are consummated bilaterally between individual counter-parties, and physically delivered either within or across the physical control areas of the transmission owners from the source generator to the sink load. Transacting counter-parties are required to reserve and purchase transmission services from the intervening transmission owners at their FERC approved tariff rates. Included with these transmission services are the reserve and ancillary costs. Energy prices in the South Central region are determined and agreed to in bilateral negotiations between representatives of the transacting counter-parties, using market information gleaned by the individual marketing agents arranging the transactions.

In the South Central area, including Entergy’s service territory, the present energy market is not a centralized market and does not have an independent system operator as is found in the Northeast markets. The Company presently has long-term all requirements contracts with 11 Louisiana Distribution Cooperatives, and long-term contracts with the Municipal Energy Agency of Mississippi, South Mississippi Electric Power Association and Southwestern Electric Power Company. The Distribution Cooperatives serve approximately 300,000 to 350,000 retail customers.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In the Southeast portion of the United States, Entergy and Southern Company recently discontinued their RTO initiative, SeTrans. On March 31, 2004, Entergy filed with FERC a proposal to have an independent person monitor the Entergy operation of the transmission system. FERC has not ruled on this request. Also, it is unclear at this time how these recent developments will impact the Company, or whether another RTO proposal will replace the SeTrans initiative.


12.	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. Fixed costs include the cost of operating common facilities. All variable costs are borne in proportion to the energy delivered to the owners. The Company’s statements of operations include its share of all fixed and variable costs of operating the unit.


13.	Decommissioning Fund

The Company is required by the State of Louisiana Department of Environmental Quality (“DEQ”) to rehabilitate its Big Cajun II ash and wastewater impoundment areas upon removal from service of the Big Cajun II facilities. On July 1, 1989, a guarantor trust fund (the “Solid Waste Disposal Trust Fund”) was established to accumulate the estimated funds necessary for such purpose. The Company’s predecessor deposited $1.06 million in the Solid Waste Disposal Trust Fund in 1989, and funded $116,000 annually thereafter, based upon an estimated future rehabilitation cost (in 1989 dollars) of approximately $3.5 million and the remaining estimated useful life of the Big Cajun II facilities. Prior to January 1, 2003, cumulative contributions to the Solid Waste Disposal Trust Fund and earnings on the investments therein were accrued as a decommissioning liability. At June 30, 2004 and December 31, 2003, the carrying value of the trust fund investments and the related accrued decommissioning liability was approximately $4.9 million. 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.


14.	Guarantees

In November 2002, the FASB issued Interpretation No. (“FIN”) 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor’s fiscal year end. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002. The interpretation addresses the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees. The interpretation also clarifies the requirements related to the recognition of a liability by a guarantor at the inception of the guarantee for the obligations the guarantor has undertaken in issuing the guarantee.

In connection with the application of push down accounting, all outstanding guarantees were considered new; accordingly, the Company applied the provisions of FIN 45 to all of those guarantees. Each guarantee was reviewed for the requirement to recognize a liability at inception.

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 June 30, 2004 and December 31, 2003, the Company’s obligations pursuant to its guarantees of the performance of its subsidiaries totaled approximately $13 million and $13 million, respectively. In addition, the Company had

NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

one guarantee related to the purchase of transmission service that has an indeterminate value at June 30, 2004 and December 31, 2003.

In June 2002, NRG Peaker issued $325 million of secured bonds to make loans to affiliates which own natural gas fired “peaker” electric generating projects. At June 30, 2004 and December 31, 2003, $243.1 million and $239.3 million, respectively, remains outstanding. NRG Peaker 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 June 30, 2004 and December 31, 2003, Bayou Cove had an intercompany loan outstanding in the amount of $80.3 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 $243.1 million at June 30, 2004.

The Company is a guarantor under the debt issued by the Company’s ultimate parent, NRG Energy. NRG Energy issued $1.25 billion of 8% Second Priority Notes on December 23, 2003, due and payable on December 15, 2013. On January 28, 2004, NRG Energy also issued $475.0 million of Second Priority Notes, under the same terms and indenture as its December 23, 2003 offering.

NRG Energy’s payment obligations under the notes and all related Parity Lien Obligations are guaranteed on an unconditional basis by each of NRG Energy’s current and future restricted subsidiaries, of which the Company is one. The notes are jointly and severally guaranteed by each of the guarantors. The subsidiary guarantees of the notes are secured, on a second priority basis, equally and ratably with any future Parity Lien Debt, by security interest in all of the assets of the guarantors, except certain excluded assets, subject to liens securing parity lien debt and other permitted prior liens.

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


	Guarantee/
	Maximum		Expiration
	Exposure	Nature of Guarantee	Date		Triggering Event


	(In thousands of dollars)
NRG Energy Second Priority Notes due 2013	$1,753,000	Obligations under credit agreement		2013	Nonperformance


15.	Income Taxes

The Company is included in the consolidated tax return filings as a wholly owned indirect subsidiary of NRG Energy. Reflected in the financial statements and notes below are separate company federal and state tax provisions as if the Company had prepared separate filings. An income tax provision has been established on the accompanying consolidated financial statements as of the earliest period presented in order to reflect income taxes as if the Company filed its own tax return. The Company’s ultimate parent, NRG Energy, does not have a tax allocation agreement with its subsidiaries and prior to January 1, 2003, income taxes were not recorded or allocated to non tax paying entities or entities such as the Company which are treated as disregarded entities for tax purposes. Because the Company is not a party to a tax sharing agreement, current tax expense (benefit) is recorded as a capital contribution from (distribution to) the Company’s parent. The cumulative effect of recording an income tax provision (benefit) and deferred taxes resulted in recording as of December 31, 2002, a net deferred tax asset of $35.7 million, a valuation allowance to offset the net deferred tax asset and no impact to members’ equity.

Income taxes for the six months ended June 30, 2004 was a tax expense of $10.2 million compared to a tax expense of $0.0 million for the same period in 2003. The tax expense for the six months ended June 30,

NRG SOUTH CENTRAL GENERATING LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

2004 includes federal tax expense of $8.2 million and state tax expense of $2.0 million. The tax expense for the same period in 2003 includes federal tax expense of $0.0 million and state tax expense of $0.0 million.

Income taxes for the three months ended June 30, 2004 was a tax expense of $5.6 million compared to a tax expense of $0.0 million for the same period in 2003. The tax expense for the three months ended June 30, 2004 includes federal tax expense of $4.7 million and state tax expense of $0.9 million. The tax expense for the same period in 2003 includes federal tax expense of $0.0 million and state tax expense of $0.0 million.

The tax expense in 2004 is due to a reduction in deferred tax assets without a tax benefit for the corresponding reduction in valuation allowance. Due to the uncertainty of realization of deferred tax assets related to net operating losses and other temporary differences, the Company’s net deferred tax assets at December 5, 2003, were offset by a full valuation allowance of $237.8 million in accordance with SFAS No. 109. SOP 90-7 requires reductions in the valuation allowance subsequent to push down accounting as of December 5, 2003 should first reduce intangible assets until exhausted and thereafter be reported as a direct addition to paid-in-capital. Consequently, our effective tax rate in subsequent years will not benefit from reductions in the valuation allowance. For 2003, the tax expense resulting from a decrease in deferred tax assets was offset by a corresponding decrease in valuation allowance which had been established in an earlier year.

The effective income tax rate for the period ended June 30, 2004, differs from the statutory federal income tax rate of 35% due to state taxes and to the requirement that reductions to the valuation allowance as of December 5, 2003 (push down accounting) should first reduce intangible assets until exhausted. The effective income tax rate for the period ended June 30, 2003, differs from the statutory federal income tax rate of 35% due to state taxes.

As of June 30, 2004, the valuation allowance against net operating loss carryforwards was $89.0 million and the valuation allowance against other deferred tax assets was $138.4 million. As of December 31, 2003, a valuation allowance of $91.3 million was provided to account for potential limitations on utilization of net operating loss carryforwards, and a valuation allowance of $146.3 million was provided for other deferred tax assets. If unused, the net operating loss carryforward of $218.9 million generated in 2001 through 2003 will expire starting in 2021 and running through 2023.