NRG SOUTH CENTRAL GENERATING LLC - 10-Q Quarterly Report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


[X]		Quarterly report pursuant to section 13 or 15(d) of the securities exchange act of 1934

[ ]		Transition report pursuant to section 13 or 15(d) of the securities exchange act of 1934


For the Quarter Ended: September 30, 2002		Commission File No. 333-48900

NRG South Central Generating LLC

(Exact name of Registrant as specified in its charter)


Delaware (State or other jurisdiction of incorporation or organization)		41-1963217 (I.R.S. Employer Identification No.)

901 Marquette Avenue, Suite 2300 Minneapolis, Minnesota (Address of principal executive offices)		55402 (Zip Code)

(612) 373-5300
(Registrant’s telephone number, including area code)

None
Former name, former address and former fiscal year, if changed since last report

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

Indicate by checkmark whether the Registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

TABLE OF CONTENTS


	Item. 1 Consolidated Financial Statements and Notes
		CONSOLIDATED STATEMENTS OF OPERATIONS
		CONSOLIDATED BALANCE SHEETS
		CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY
		CONSOLIDATED STATEMENTS OF CASH FLOWS
		NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Item 3. Quantitative and Qualitative Disclosures About Market Risk
	Item 4. Controls and Procedures
Part II — OTHER INFORMATION
	Item 1. Legal Proceedings
	Item 3. Defaults on Senior Securities
	Item 6. Exhibits and Reports on Form 8-K
		Cautionary Statement Regarding Forward-Looking Information
Signatures
EX-99.1 Officers' Certification

Index


Part I
Item 1	Consolidated Financial Statements and Notes		1
	Consolidated Statements of Income		1
	Consolidated Balance Sheets		2
	Consolidated Statements of Members’ Equity		3
	Consolidated Statements of Cash Flows	4
	Notes to Consolidated Financial Statements	5
Item 2	Management’s Discussion and Analysis of Financial Condition and
	Results of Operation	18
Item 3	Quantitative and Qualitative Disclosures About Market Risk	25
Item 4	Controls and Procedures	25
Part II
Item 1	Legal Proceedings	25
Item 3	Defaults on Senior Securities	26
Item 4	Controls and Procedures	26
Item 6	Exhibits and Reports on Form 8-K	27
	Cautionary Statement Regarding Forward Looking Information	28
SIGNATURES		29
CERTIFICATION		30

NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)


			Three Months			Three Months			Nine Months			Nine Months
			Ended			Ended			Ended			Ended
			September 30,			September 30,			September 30,			September 30,
(Thousands of Dollars)			2002			2001			2002			2001

Operating revenues
	Revenues from majority owned operations		$	102,852		$	110,185		$	296,030		$	313,312
	Earnings (losses) of unconsolidated affiliates			1,248			—			(3,146	)		—

		Total operating revenues and equity earnings		104,100			110,185			292,884			313,312
Operating costs and expenses
	Cost of operations			68,041			81,977			191,073			219,487
	Depreciation and amortization			9,306			7,824			27,245			21,913
	General and administrative expenses			1,982			1,379			6,600			5,147
	Write down and losses on equity method investments			48,392			—			48,392			—
	Special charges			12,208			—			12,208			—

Operating income				(35,829	)		19,005			7,366			66,765
Other income (expense)
	Other income, net			154			179			456			473
	Interest expense			(19,094	)		(18,183	)		(54,315	)		(54,653	)

Net income (loss)			$	(54,769	)	$	1,001		$	(46,493	)	$	12,585

See accompanying notes to consolidated financial statements

NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)


					September 30,		December 31,
(Thousands of Dollars)					2002		2001

				ASSETS
CURRENT ASSETS:
	Cash and cash equivalents				$	—	$	3,208
	Restricted cash					41,214		—
	Accounts receivable, net					43,146		44,122
	Notes receivable —current					3,000		—
	Inventory					60,301		52,916
	Prepaid expenses					6,194		2,627

		Total current assets				153,855		102,873
NON-CURRENT ASSETS
	Equity investments in affiliates					—		50,233
	Property, plant & equipment, net of accumulated depreciation of $75,731 and $50,556					1,267,063		1,166,512
	Notes receivable — non-current					1,500		—
	Decommissioning fund investments					4,588		4,336
	Deferred financing costs, net of accumulated amortization of $1,435 and $750					30,446		9,969
	Derivative instruments valuation — at market					1,466		—
	Other assets, net of accumulated amortization of $492 and $458					7,167		7,356

		Total assets			$	1,466,085	$	1,341,279

			LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES:
	Current portion of long-term debt				$	858,103	$	25,500
	Revolving line of credit					—		40,000
	Accounts payable					15,884		324
	Accounts payable-affiliates					66,433		27,246
	Accrued fuel and purchased power expense					16,010		26,599
	Accrued interest					39,191		20,453
	Checks in excess of cash					4,225		5,865
	Other current liabilities					9,174		6,161

		Total current liabilities				1,009,020		152,148
Long-term debt						—		738,000
Other non-current liabilities						6,298		5,600
Derivative instruments valuation-at market						1,736		18

		Total liabilities				1,017,054		895,766
Commitments and contingencies
MEMBERS’ EQUITY						449,031		445,513

		Total liabilities and members’ equity			$	1,466,085	$	1,341,279

See accompanying notes to consolidated financial statements.

NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY
(Unaudited)

For the Three Months Ended September 30, 2002 and 2001


							Accumulated
							Other
		Member					Comprehen-		Total
		Contributions/		Accumulated			sive		Members'
(Thousands of Dollars)		Distributions		Income/(Loss)			Income		Equity

Balances at June 30, 2001		$	352,519	$	37,600		$	—	$	390,119
Net income			—		1,001			—		1,001

	Total comprehensive income for the period ended September 30, 2001		—		1,001			—		1,001
Member contributions, net			11,253		—			—		11,253

Balances at September 30, 2001		$	363,772	$	38,601		$	—	$	402,373

Balances at June 30, 2002		$	459,400	$	44,400		$	—	$	503,800
Net loss			—		(54,769	)		—		(54,769	)

	Total comprehensive loss for the period ended September 30, 2002		—		(54,769	)		—		(54,769	)

Member contributions, net			—		—			—		—

Balances at September 30, 2002		$	459,400	$	(10,369	)	$	—	$	449,031

For the Nine Months Ended September 30, 2002 and 2001


							Accumulated
							Other
		Member					Comprehen-			Total
		Contributions/		Accumulated			sive			Members'
(Thousands of Dollars)		Distributions		Income/(Loss)			Income			Equity

Balances at December 31, 2000		$	300,746	$	26,016		$	—		$	326,762
Cumulative effect upon adoption of SFAS 133			—		—			500			500
Impact of SFAS No. 133 for period ended September 30, 2001			—		—			(500	)		(500	)
Net income			—		12,585			—			12,585

	Total comprehensive income for the period ended September 30, 2001		—		12,585			—			12,585
Member contributions, net			63,026		—			—			63,026

Balances at September 30, 2001		$	363,772	$	38,601		$	—		$	402,373

Balances at December 31, 2001		$	409,389	$	36,124		$	—		$	445,513
Net loss			—		(46,493	)		—			(46,493	)

	Total comprehensive loss for the period ended September 30, 2002		—		(46,493	)		—			(46,493	)
Member contributions, net			50,011		—			—			50,011

Balances at September 30, 2002		$	459,400	$	(10,369	)	$	—		$	449,031

See accompanying notes to consolidated financial statements.

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


		Nine Months			Nine Months
		Ended			Ended
(Thousands of Dollars)		September 30, 2002			September 30, 2001

Cash flows from operating activities:
Net (loss) income		$	(46,493	)	$	12,585
Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities:
	Losses of unconsolidated affiliates		3,146			—
	Depreciation and amortization		25,380			21,913
	Noncash loss on disposal of property		1,865
	Write down of equity method investments		48,392			—
	Special charges		12,208			—
	Amortization of deferred finance costs		685			508
	Unrealized loss on energy contracts		252			1,197
Changes in assets and liabilities:
	Accounts receivable		976			11,519
	Inventory		(7,385	)		(15,848	)
	Prepaid expenses		(3,567	)		(2,325	)
	Accounts payable		15,560			1,362
	Accounts payable-affiliates		(1,536	)		(44,611	)
	Accrued interest		18,738			(17,303	)
	Accrued fuel and purchased power expense		(10,589	)		10,099
	Other current liabilities		3,512			10,764
	Changes in other assets and liabilities		447			13

Net cash provided by (used in) operating activities			61,591			(10,127	)

Cash flows from investing activities:
	Capital expenditures		(12,443	)		(2,654	)
	Increase in notes receivable		(4,500	)		—
	Increase in restricted cash		(41,214	)		—
	Investment in decommissioning fund		(252	)		(443	)
	Investments in projects		—			(229	)

Net cash used in investing activities			(58,409	)		(3,326	)

Cash flows from financing activities:
	Contributions by members		48,000			5,051
	Net (payments)/proceeds on revolver		(40,000	)		40,000
	Repayments of long-term borrowings		(12,750	)		(25,250	)
	Checks in excess of cash		(1,640	)		—
	Deferred financing costs		—			(356	)

Net cash (used in) provided by financing activities			(6,390	)		19,445

Net increase in cash and cash equivalents			(3,208	)		5,992
Cash and cash equivalents at beginning of period			3,208			3,146

Cash and cash equivalents at end of period		$	—		$	9,138

Supplemental Disclosures of Noncash Information:
	Capital expenditures paid by affiliate	$	127,555		$	57,976
	Deferred finance costs paid by affiliate	$	21,162		$	—
	Noncash contribution to non-guarantor subsidiary	$	2,011		$	—

See accompanying notes to consolidated financial statements.

NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NRG South Central Generating LLC (NRG South Central or the Company), a Delaware Limited Liability Company formed in 2000, 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), NRG Sabine River Works LP LLC (Sabine River Works LP), NRG Sabine River Works GP LLC (Sabine River Works GP), NRG Bayou Cove Peaking Power LLC (Bayou Cove) and Big Cajun II Unit 4 LLC (Big Cajun II). 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 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 (the Cajun Facilities). 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 megawatt (MW) simple cycle gas peaking facility in Sterlington, Louisiana. Louisiana Generating purchases the capacity and is entitled to all energy from Sterlington. In December 2000, Sabine River Works LP and Sabine River Works GP acquired a 49% limited partnership interest and a 1% general partnership interest, respectively, in SRW Cogeneration Limited Partnership, a Delaware Limited Partnership that owns and operates an approximately 450 MW natural gas-fired cogeneration plant located near Orange, Texas. Big Cajun Peaking was formed to develop, construct and operate a 238 MW gas-fired peaking generating facility located in New Roads, Louisiana. Louisiana Generating purchases the capacity of, and is entitled to all energy produced from, Big Cajun Peaking. Bayou Cove was formed to develop, construct and own a 320 MW gas-fired peaking generating facility located in Jennings, Louisiana.

The acquisition of the Cajun Electric assets was financed in part through the issuance, by NRG South Central, of $800 million aggregate principal amount of senior secured bonds. Louisiana Generating is a guarantor of the bonds. NRG New Roads Holdings, NRG Sterlington Power, NRG Sabine River Works LP, NRG Sabine River Works GP, Big Cajun Peaking, and Bayou Cove have been designated as “unrestricted subsidiaries” of NRG South Central under the indenture governing the bonds, and are not guarantors of the bonds.

The accompanying unaudited consolidated financial statements have been prepared in accordance with Securities and Exchange Commission (SEC) regulations for interim financial information and with the instructions to Form 10-Q. 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 by the Company are set forth in Item 8 — Note 2 to the Company’s financial statements in its annual report on Form 10-K for the year ended December 31, 2001 (Form 10-K). The following notes should be read in conjunction with such policies and other disclosures in the Form 10-K. 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 consolidated financial position of the Company as of September 30, 2002 and December 31, 2001, the results of its operations and members’ equity for the three and nine months ended September 30, 2002 and 2001, and its cash flows for the nine months ended September 30, 2002 and 2001.

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

Note 1 — Recent Developments

In December 2001, Moody’s Investor Service (Moody’s) placed NRG Energy’s long-term senior unsecured debt rating on review for possible downgrade. In response to this threat to NRG Energy’s investment grade rating, on February 17, 2002, Xcel Energy announced a financial improvement plan for NRG Energy, which included an initial step of acquiring 100% of NRG Energy through a tender offer to exchange all of the outstanding shares of NRG Energy common stock for Xcel Energy common shares. In addition, the plan included financial support to NRG Energy from Xcel Energy; marketing certain NRG Energy generating assets for possible sale; canceling and deferring capital spending for NRG Energy projects; and combining certain of NRG Energy’s functions with Xcel Energy’s system and organization. On June 3, 2002, Xcel Energy completed its exchange offer for the 26% of NRG Energy’s shares that had been previously publicly held. Xcel Energy offered NRG Energy shareholders 0.50 shares of Xcel Energy common stock for each outstanding share of NRG Energy common stock, representing a $650 million purchase price. During 2002, Xcel Energy provided NRG Energy with $500 million of cash infusions. Throughout this period of time, Xcel Energy was in discussions with credit agencies and believed that its actions would be sufficient to avoid a downgrade of NRG Energy’s credit rating.

However, even with NRG Energy’s efforts to avoid a downgrade, unexpectedly on July 26, 2002, Standard & Poors’ (S&P) downgraded NRG Energy’s senior unsecured bonds below investment grade, and three days later Moody’s also downgraded NRG Energy’s senior unsecured debt rating below investment grade. Over the next few months NRG senior unsecured debt, as well as the secured NRG Northeast Generating LLC bonds and the secured NRG South Central Generating LLC bonds, were downgraded multiple times. After NRG Energy failed to make the payment obligations due under certain unsecured bond obligations on September 16, 2002, both Moody’s and S&P lowered their ratings on NRG Energy’s unsecured bonds once again. Currently, unsecured bond obligations of NRG Energy carry a rating of between CCC and D, depending on both the specific debt issue and the rating agency rating system. NRG South Central Generating LLC bonds currently carry a rating of D with S&P and Caa1 with Moody’s.

Many of the corporate guarantees and commitments of NRG Energy and its subsidiaries require that they be supported or replaced with letters of credit or cash collateral within 5 to 30 days of a ratings downgrade below Baa3 or BBB- by Moody’s or Standard & Poor’s, respectively. As a result of the downgrades on July 26 and July 29, NRG Energy estimated that it would be required to post collateral ranging from $1.1 billion to $1.3 billion. Although the credit rating downgrades were not expected to occur, NRG Energy believed that it could meet the collateral requirements that would result from such an occurrence with available cash, operating cash flows, equity contributions from Xcel Energy, proceeds from asset sales and the issuance of bonds into the capital markets or as a private placement.

On August 19, 2002, NRG Energy executed a Collateral Call Extension Letter (CCEL) with various secured project lender groups in which the banks agreed to extend until September 13, 2002, the deadline by which NRG Energy was to post its approximately $1.0 billion of cash collateral in connection with certain bank loan agreements.

Subsequently, and effective as of September 13, 2002, NRG Energy and these various secured project lenders entered into a Second Collateral Call Extension Letter (Second CCEL) that extended until November 15, 2002, the deadline for NRG Energy to post such collateral. Under the Second CCEL, NRG Energy agreed to submit to the lenders a comprehensive restructuring plan. NRG Energy submitted this plan on November 4, 2002 and is working with the lenders on an overall restructuring of its debt (see further discussion below). The extension agreements did not, however, waive other events of default, including failure to make principal and/or interest payments when due or failure to comply with financial covenants. Nor did the extension agreements waive the rights of the bank groups or bondholders to pursue any rights and remedies in respect of such other defaults. The November 15, 2002, deadline of the second CCEL has passed and NRG Energy has not posted the required collateral. Because NRG Energy has failed to make principal and interest payments when due, and is in breach of other covenants in various financing agreements, NRG Energy is in default of various debt instruments. By reason of these defaults, the lenders are able, if they so choose, to seek to enforce their remedies, which would likely lead to a bankruptcy filing by NRG Energy and certain of its subsidiaries, including the Company.

Starting in August 2002, NRG Energy engaged in the preparation of a comprehensive business plan and forecast. The business plan detailed the strategic merits and financial value of NRG Energy’s projects and operations. It also anticipates that NRG Energy will function independently from Xcel Energy and thus all plans and efforts to combine certain functions of the companies were terminated. NRG Energy utilized independent electric revenue forecasts from an outside energy markets consulting firm to develop forecasted cash flow information included in the business plan. Management concluded that the forecasted free cash flow available to NRG Energy after servicing project-level obligations will be insufficient to service recourse debt obligations. Based on this information and in consultation with Xcel Energy and its financial advisor, NRG Energy prepared and submitted a restructuring plan on November 4, 2002 to various lenders, bondholders and other creditor groups (collectively, “NRG Energy’s Creditors”) of NRG Energy and its subsidiaries. The restructuring plan is expected to serve as a basis for negotiations with NRG Energy’s Creditors in a financially-restructured NRG Energy and, among other things, proposes (i) holders of secured (project-level) debt would either (a) have their debt reinstated with agreed modifications or (b) receive the collateral securing such debt and a claim or claims to the extent such debt is under-secured; (ii) holders of unsecured debt, holders of secured recourse claims against NRG Energy, and holders of other general unsecured claims against NRG Energy would receive a pro rata share of (a) an aggregate of $500 million of junior secured debt of reorganized NRG Energy and (b) 95% of the common equity of reorganized NRG Energy; and (iii) holders of project-level general unsecured claims that are non-recourse to NRG Energy would receive a pro rata share of the remaining 5% of the common equity of a reorganized NRG Energy.

On November 6, 2002, lenders to NRG Energy accelerated approximately $1.1 billion of NRG Energy’s debt under a construction revolver financing facility, rendering the debt immediately due and payable. This action terminated the Second CCEL in effect between NRG Energy and its major lenders. The extension letter was previously scheduled to expire November 15, 2002. Based on discussions with the construction revolver lenders it is NRG Energy’s understanding that the administrative agent, Credit Suisse First Boston, issued the acceleration notice to preserve certain rights under the construction revolver financing agreements. NRG Energy believes that the administrative agent intends to forbear in the immediate exercise of any rights and remedies against the Company.

The restructuring plan also includes a proposal by Xcel Energy that in return for a release of any and all claims against Xcel Energy, upon consummation of the restructuring, Xcel Energy would pay $300 million to NRG Energy and surrender its equity ownership of NRG Energy.

If an agreement were reached with NRG Energy’s Creditors on a restructuring plan, it would most likely lead to NRG Energy commencing a Chapter 11 bankruptcy case and immediately seeking approval of a prenegotiated plan of reorganization. The absence of an agreement will increase the possibility of NRG Energy and various subsidiaries, including the Company, seeking protection under the bankruptcy laws.

Throughout the restructuring process, NRG Energy seeks to operate the business in a manner that management believes will offer to creditors similar protection as would be offered by a bankruptcy court. NRG Energy attempts to preserve the enterprise value of the business and to treat creditors within each creditor class without preference, unless otherwise agreed to by advisors to all potentially affected creditors. By operating the Company within this framework, NRG Energy desires to mitigate the risk that creditors will pursue involuntary bankruptcy proceedings against NRG Energy or its material subsidiaries including NRG South Central.

Prior to the NRG Energy downgrades, the debt service reserve account of the Company was funded with a letter of guarantee from the parent company. Following the downgrade , the debt service reserve account was required to be funded with cash. On August 25 NRG Energy failed to fund the debt service reserve account. The 30 day cure period expired on September 25, which created an event of default, and gave the bond holders rights of acceleration. The project is precluded from making payments to NRG Energy. As a result of this default and the payment default described below, the long-term portion of the debt has been reclassified to a current liability, as it is potentially callable within the next twelve months.

On September 16, 2002 the Company failed to make approximately $47 million in combined principal and interest payments on the 8.962% Series A-1 senior secured bonds due 2016 and 9.479% Series B-1 senior secured bonds due 2024. The Company had 15 days to make principal and interest payments to the Company's A-1 and B-1 Series bond holders to avoid an event of default on these bonds. The 15 day grace period to make payment ended October 1, 2002 and the Company did not make the required payments. As a result, the Company is in default on these bonds.

As part of the overall NRG restructuring plan, the Company is in negotiations with the financial advisor representing the NRG South Central bond holders.

The credit rating downgrades, defaults under certain agreements, increased collateral requirements, creditor’s actions and reduced liquidity that have occurred during the quarter ended September 30, 2002 have created substantial doubt as to NRG Energy’s and the Company’s ability to continue as a going concern. The absence of a restructuring agreement will increase the possibility of NRG Energy and certain of its subsidiaries, including the Company, seeking protection under the bankruptcy laws. Such action would have a material effect on the Company and its subsidiaries.

Note 2 — Property, Plant and Equipment

Property, plant and equipment consisted of:


(Thousands of Dollars)	September 30, 2002			December 31, 2001

Land	$	15,207		$	14,308
Facilities, machinery and equipment		1,322,507			1,157,357
Office furnishings and equipment		4,331			3,618
Construction in progress		749			41,785
Less: accumulated depreciation		(75,731	)		(50,556	)

Property, plant and equipment (net)	$	1,267,063		$	1,166,512

During the nine month period ended September 30, 2002 NRG South Central recorded $140.0 million of capital expenditures, which primarily related to the construction of Bayou Cove.

Note 3 — Long and Short Term Debt

On March 30, 2001, NRG South Central entered into a 364-day, $40 million floating rate working capital revolving credit facility. The proceeds of this facility will be used to finance NRG South Central’s working capital needs. NRG South Central extended this facility in March 2002 for an additional 3 months, on substantially similar terms. NRG South Central paid down the outstanding balance in June 2002 with funds received from NRG Energy in an equity contribution, and the facility was not renewed.

On March 30, 2000, NRG South Central issued $800 million of senior secured bonds in two tranches. The first tranche was for $500 million with a coupon of 8.962% and a maturity of 2016. The second tranche was for $300 million with a coupon of 9.479% and a maturity of 2024. Interest on the bonds is payable in arrears on each

March 15 and September 15. Principal payments are due semi-annually on each March 15 and September 15. The proceeds of the bonds were used to finance NRG South Central’s acquisition of the Cajun generating facilities on March 31, 2000. On December 13, 2000, NRG South Central commenced an Exchange offer of these bonds with registered bonds that contain similar terms and conditions. The Exchange offer was closed on January 19, 2001 with all bonds being exchanged. NRG South Central made a semi-annual payment of $12.7 million on March 15, 2002. As of September 30, 2002, NRG South Central had bonds outstanding in the amount of $750.7 million.

As of October 1, 2002, the Company is in default on the senior secured bonds. As a result, the debt has been classified as current at September 30, 2002. See footnote 1 for additional information.

On June 18, 2002, NRG Peaker Finance Company LLC (NRG Peaker), a wholly owned subsidiary of NRG and affiliate of NRG South Central, issued $325 million of senior secured bonds. 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, Inc., which include the following entities: Bayou Cove Peaking Power LLC (Bayou Cove), Big Cajun I Peaking Power LLC (Big Cajun Peaking), NRG Rockford LLC and Rockford II LLC and NRG Sterlington Power LLC (Sterlington). Three of these entities, Bayou Cove, Big Cajun Peaking, and Sterlington, are wholly owned 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 (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). As of September 30, 2002, Bayou Cove, Big Cajun Peaking and Sterlington had intercompany loans outstanding in the amount of $107.4 million. These bonds are in default and have accordingly been classified as current as of September 30, 2002. Pursuant to the issuance of the bonds, approximately $21.2 million of deferred finance costs were allocated to Bayou Cove, Big Cajun Peaking and Sterlington. These costs represent prepayment of a credit insurance policy (Bond Policy) with XL Capital Assurance. This Bond Policy is a financial guaranty insurance policy that guarantees payment of scheduled principal and interest payments on the bonds.

The bonds are secured by a pledge of membership interests in NRG Peaker and a security interest in all of its assets, which initially consisted of notes evidencing loans to the affiliate project owners, including Bayou Cove, Big Cajun Peaking and Sterlington. The project owners' jointly and severally guarantied the entire principal amount of the bonds and interest on such principal amount. The project owner guaranties are secured by a pledge of the membership interest in three of five project owners, including Bayou Cove, and a security interest in substantially all of the project owners' assets related to the peaker projects, including equipment, real property rights, contracts and permits. NRG Energy has entered into a contingent guaranty agreement in favor of the collateral agent for the benefit of the secured parties, under which it agreed to make payments to cover scheduled principal and interest payments on the bonds and regularly scheduled payments under the interest rate swap agreement, to the extent that the net revenues from the peaker projects are insufficient to make such payments, in specified circumstances. This financing contains a cross-default provision related to the failure by NRG Energy to make payment of principal, interest or other amounts due on debt for borrowed money in excess of $50 million of payment defaults by NRG Energy, a covenant that was violated in October 2002. In addition, liens were placed against the Bayou Cove facility resulting in an additional default. NRG Peaker is in the process of getting such liens released.

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 interest rate swap counter-party will have a security interest in the collateral for the bonds and the collateral for the project owner guaranties. Net payments to be made by NRG Peaker under the interest rate swap agreement are guaranteed pursuant to a separate financial guaranty insurance policy, the issuer of which has a security interest in the collateral for the bonds and the collateral for the project owner guaranties.

Note 4 — Inventory

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


(Thousands of Dollars)	September 30, 2002		December 31, 2001

Coal	$	44,065	$	36,571
Spare parts		15,433		15,582
Fuel oil and diesel fuel		803		763

Total	$	60,301	$	52,916

Note 5 — Derivative Instruments and Hedging Activity

On January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133), as amended by SFAS No. 137 and SFAS No. 138. SFAS No. 133 requires the Company to record all derivatives on the balance sheet at fair value. Changes in the fair value of non-hedge derivatives are immediately recognized in earnings. Changes in fair values of derivatives accounted for as hedges are either recognized in earnings as offsets to the changes in fair value of related hedged assets, liabilities and firm commitments or for forecasted transactions, deferred and recorded as a component of accumulated other comprehensive income (OCI) until the hedged transactions occur and are recognized in earnings. The ineffective portion of a hedging derivative instrument’s change in fair value is immediately recognized in earnings. The Company also formally assesses, both at inception and at least quarterly thereafter, whether the derivatives used in hedging transactions are highly effective in offsetting the changes in either the fair value or cash flows of the hedged item. This assessment includes all components of each derivative’s gains or losses unless otherwise noted. When it is determined that a derivative ceases to be a highly effective hedge, hedge accounting is discontinued.

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 September 30, 2002, the Company had various commodity contracts extending through March 2004. None of these contracts are designated as hedging instruments.

Accumulated Other Comprehensive Income

The following table summarizes the effects of SFAS No. 133 on the Company’s OCI balance:


		Three Months Ended				Nine Months Ended
		September 30,				September 30,
Gains/(Losses)
(Thousands of Dollars)		2002		2001		2002		2001

Beginning Balance		$	—	$	—	$	—	$	—
	Cumulative impact on adoption of SFAS No. 133		—		—		—		500
	Previously deferred amounts unwound from OCI		—		—		—		(500	)
	Mark to market to hedge contracts		—		—		—		—

Ending Balance		$	—	$	—	$	—	$	—

During the three and nine months ended September 30, 2002, the Company deferred no gains or losses to OCI.

Statement of Operations

The following tables summarize the effects of SFAS No. 133 on the Company’s statement of operations for the quarters ended September 30, 2002 and 2001:


		Three Months Ended					Nine Months Ended
Gains (Losses)		September 30,					September 30,
(Thousands of Dollars)		2002			2001		2002			2001

Revenues		$	7		$		$	(169	)	$
Operating costs			(22	)		13,471		(83	)		(1,197	)

	Total statement of operations impact	$	(15	)	$	13,471	$	(252	)	$	(1,197	)

During the three and nine months ended September 30, 2002 and 2001, the Company recognized no gain or loss due to ineffectiveness of commodity cash flow hedges, and no components of the company’s derivative instruments’ gains or losses were excluded from the assessment of effectiveness.

The Company’s earnings for the three months ended September 30, 2002 and 2001 were decreased by an unrealized loss of $15,000 and increased by an unrealized gain of $13.5 million, respectively. For the nine months ended September 30, 2002 and 2001 the Company’s earnings were decreased by unrealized losses of $252,000 and $1.2 million, respectively, associated with changes in the fair value of energy related derivative instruments not accounted for as hedges.

Note 6 — Condensed Consolidating Financial Information

The following tables set forth the consolidating financial statements of NRG South Central Generating LLC (Bond Issuer); Louisiana Generating LLC (Bond Guarantor); NRG New Roads Holding LLC, NRG Sterlington Power LLC, Big Cajun I Peaking Power LLC, NRG Sabine River Works GP LLC, NRG Sabine River Works LP LLC and NRG Bayou Cove Peaking Power LLC (unrestricted, non-guarantor subsidiaries). The condensed consolidating financial statements present the unrestricted non-guarantor subsidiaries on a combined basis. The condensed consolidating financial statements as of and for the three and nine months ended September 30, 2002 and 2001 have been derived from the unaudited historical consolidated financial statements of NRG South Central. The consolidating balance sheet as of December 31, 2001 has been derived from the audited historical consolidated balance sheet of NRG South Central.

NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES
CONSOLIDATING BALANCE SHEET
September 30, 2002
(Unaudited)


				Louisiana		South Central
		Unrestricted		Generating		Generating
		Non-Guarantor		LLC		LLC		Eliminations			Consolidated
(Thousands of Dollars)		Subsidiaries		(Bond Guarantor)		(Bond Issuer)		(1)			Balance

ASSETS
CURRENT ASSETS:
Restricted cash		$	2,105	$	39,109	$	—	$	—		$	41,214
Accounts receivable, net			540		42,606		—		—			43,146
Interest receivable			—		—		39,191		(39,191	)		—
Notes receivable current			—		3,000		—		—			3,000
Intercompany note receivable bonds — current			—		—		750,750		(750,750	)		—
Inventory			970		59,331		—		—			60,301
Prepaid expenses			431		5,763		—		—			6,194

Total current assets			4,046		149,809		789,941		(789,941	)		153,855
Equity investments in affiliates			—		—		444,621		(444,621	)		—
Property, plant & equipment, net			295,955		971,108		—		—			1,267,063
Notes receivable — long term			—		1,500		—		—			1,500
Decommissioning fund investment			—		4,588		—		—			4,588
Deferred financing costs, net			20,799		9,647		—		—			30,446
Derivative instruments valuation - - at market			—		—		1,466		—			1,466
Other assets			—		2,280		4,887		—			7,167

	Total assets	$	320,800	$	1,138,932	$	1,240,915	$	(1,234,562	)	$	1,466,085

LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES:
Current portion of long-term debt		$	107,353	$	—	$	750,750	$	—		$	858,103
Note payable — affiliate			—		750,750		—		(750,750	)		—
Accounts payable			9,023		6,861		—		—			15,884
Accounts payable-affiliates			60,103		6,130		200		—			66,433
Accrued fuel, purchased power and transmission expense			—		16,010		—		—			16,010
Accrued interest			2,120		37,071		39,191		(39,191	)		39,191
Checks in excess of cash			2,205		2,020		—		—			4,225
Other current liabilities			213		8,954		7		—			9,174

	Total current liabilities		181,017		827,796		790,148		(789,941	)		1,009,020
Other non-current liabilities			—		6,298		—		—			6,298
Derivative instruments valuation at market			—		—		1,736		—			1,736

	Total liabilities		181,017		834,094		791,884		(789,941	)		1,017,054
MEMBERS’ EQUITY			139,783		304,838		449,031		(444,621	)		449,031

	Total liabilities and members’ equity	$	320,800	$	1,138,932	$	1,240,915	$	(1,234,562	)	$	1,466,085

(1)

All significant intercompany transactions have been eliminated in consolidation.

NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES
CONSOLIDATING STATEMENT OF OPERATIONS
For the Nine Months Ended September 30, 2002
(Unaudited)


						Louisiana
						Generating			South Central
			Unrestricted,			LLC			Generating
			Non-Guarantor			(Bond			LLC			Eliminations			Consolidated
(Thousands of Dollars)			Subsidiaries			Guarantor)			(Bond Issuer)			(1)			Balance

Operating Revenues
	Revenues from wholly-owned operations		$	21,810		$	295,674		$	—		$	(21,454	)	$	296,030
	Equity earnings of unconsolidated affiliates			(3,146	)		—			—			—			(3,146	)

		Total operating revenues and equity earnings		18,664			295,674			—			(21,454	)		292,884
Operating costs and expenses
	Cost of operations			5,222			207,042			263			(21,454	)		191,073
	Depreciation and amortization			4,614			22,631			—			—			27,245
	General and administrative expenses			1,335			4,507			758			—			6,600
	Write-down of Equity Method investments			48,392			—			—			—			48,392
	Special charges			12,000			208			—			—			12,208

Operating income				(52,899	)		61,286			(1,021	)		—			7,366
Other income/(expense)
	Other income, net			40			416			54,315			(54,315	)		456
	Equity in earnings of subsidiaries			—			—			(45,472	)		45,472			—
	Interest expense			(1,592	)		(52,723	)		(54,315	)		54,315			(54,315	)

Net Income			$	(54,451	)	$	8,979		$	(46,493	)	$	45,472		$	(46,493	)

NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES
CONSOLIDATING STATEMENT OF OPERATIONS
For the Three Months Ended September 30, 2002
(Unaudited)


						Louisiana
						Generating			South Central
			Unrestricted,			LLC			Generating
			Non-Guarantor			(Bond			LLC			Eliminations			Consolidated
(Thousands of Dollars)			Subsidiaries			Guarantor)			(Bond Issuer)			(1)			Balance

Operating Revenues
	Revenues from wholly-owned operations		$	12,080		$	102,343		$	—		$	(11,571	)	$	102,852
	Equity earnings of unconsolidated affiliates			1,248			—			—			—			1,248

		Total operating revenues and equity earnings		13,328			102,343			—			(11,571	)		104,100
Operating costs and expenses
	Cost of operations			2,747			76,851			14			(11,571	)		68,041
	Depreciation and amortization			2,224			7,082			—			—			9,306
	General and administrative expenses			428			1,298			256			—			1,982
	Write-down of Equity Method investments			48,392			—			—			—			48,392
	Special charges			12,000			208			—			—			12,208

Operating income				(52,463	)		16,904			(270	)		—			(35,829	)
Other income/(expense)
	Other income, net			16			138			19,071			(19,071	)		154
	Equity in earnings of subsidiaries			—			—			(54,499	)		54,499			—
	Interest expense			(1,592	)		(17,502	)		(19,071	)		19,071			(19,094	)

Net Income			$	(54,039	)	$	(460	)	$	(54,769	)	$	54,499		$	(54,769	)

(1)

All significant intercompany transactions have been eliminated in consolidation.

NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES
CONSOLIDATING STATEMENT OF CASH FLOWS

For the Nine Months Ended September 30, 2002
(Unaudited)


			Unrestricted			Louisiana			South Central
			Non-Guarantor			Generating LLC			Generating LLC			Eliminations			Consolidated
(Thousands of Dollars)			Subsidiaries			(Bond Guarantor)			(Bond Issuer)			(1)			Balance

Cash Flows from operating activities:
Net income			$	(54,451	)	$	8,979		$	(46,493	)	$	45,472		$	(46,493	)
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
	Loss in earnings of unconsolidated affiliate			3,146			—			—			—			3,146
	Depreciation and amortization			4,614			20,766			—			—			25,380
	Loss on disposal of property						1,865									1,865
	Write-down of Equity Method investments			48,392			—			—			—			48,392
	Special charges			12,000			208			—			—			12,208
	Amortization of deferred finance costs			363			322			—			—			685
	Unrealized (gain)/loss on energy contracts			—			—			252			—			252
	Changes in assets and liabilities:
		Accounts receivable		229			747			—			—			976
		Inventory		(40	)		(7,345	)		—			—			(7,385	)
		Prepaid expenses		(172	)		(3,395	)		—			—			(3,567	)
		Accounts payable		9,013			6,547			—			—			15,560
		Accounts payable-affiliates		(25,085	)		22,944			46,077			(45,472	)		(1,536	)
		Accrued interest		2,120			16,618			18,738			(18,738	)		18,738
		Interest receivable		—			—			(18,738	)		18,738			—
		Intercompany note receivable - - revolver		—			—			40,000			(40,000	)		—
		Accrued fuel and purchased power expense		(484	)		(10,105	)		—			—			(10,589	)
		Other current liabilities		836			2,675			1			—			3,512
		Changes in other assets and liabilities		—			284			163			—			447

Net cash provided by (used in) operating activities				481			61,110			40,000			(40,000	)		61,591

Cash flows from investing activities:
	Capital expenditures			—			(12,443	)		—			—			(12,443	)
	Increase in notes receivable			—			(4,500	)		—			—			(4,500	)
	Intercompany note receivable			—			—			(40,000	)		40,000			—
	Payment received on loan to affiliate			—			—			12,750			(12,750	)		—
	Increase in restricted cash			(2,105	)		(39,109	)		—			—			(41,214	)
	Investment in decommissioning fund			—			(252	)		—			—			(252	)

Net cash (used in) provided by investing activities				(2,105	)		(56,304	)		(27,250	)		27,250			(58,409	)

Cash flows from financing activities:
	Contributions by members			—			48,000			40,000			(40,000	)		48,000
	Net (payments)/proceeds on revolver			—			(40,000	)		(40,000	)		40,000			(40,000	)
	Repayments of long-term borrowings			—			(12,750	)		(12,750	)		12,750			(12,750	)
	Checks in excess of cash			1,624			(3,264	)		—			—			(1,640	)

Net cash provided by (used in) financing activities:				1,624			(8,014	)		(12,750	)		12,750			(6,390	)

Net increase in cash and cash equivalents				—			(3,208	)		—			—			(3,208	)

Cash and cash equivalents, beginning of period				—			3,208			—			—			3,208

Cash and cash equivalents, end of period			$	—		$	—		$	—		$	—		$	—

(1)

All significant intercompany transactions have been eliminated in consolidation.

NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES
CONSOLIDATING BALANCE SHEET
December 31, 2001


				Louisiana			South Central
		Unrestricted		Generating			Generating
		Non-Guarantor		LLC			LLC		Eliminations			Consolidated
(Thousands of Dollars)		Subsidiaries		(Bond Guarantor)			(Bond Issuer)		(1)			Balance

				ASSETS
CURRENT ASSETS:
Restricted Cash		$	—	$	3,208		$	—	$	—		$	3,208
Accounts receivable, net			769		43,353			—		—			44,122
Intercompany note receivable bonds — current			—		—			25,500		(25,500	)		—
Interest receivable			—		—			20,453		(20,453	)		—
Inventory			930		51,986			—		—			52,916
Prepaid expenses			259		2,368			—		—			2,627

	Total current assets		1,958		100,915			45,953		(45,953	)		102,873
Equity investments in affiliates			50,233		—			440,487		(440,487	)		50,233
Intercompany note receivable-bonds			—		—			738,000		(738,000	)		—
Intercompany note receivable-revolver			—		—			40,000		(40,000	)		—
Property, plant & equipment, net			185,250		981,262			—		—			1,166,512
Decommissioning fund investment			—		4,336			—		—			4,336
Deferred financing costs, net			—		9,969			—		—			9,969
Other assets			—		2,306			5,050		—			7,356

	Total assets	$	237,441	$	1,098,788		$	1,269,490	$	(1,264,440	)	$	1,341,279

LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES:
Current portion of long-term debt		$	—	$	—		$	25,500	$	—		$	25,500
Revolving line of credit			—		—			40,000		—			40,000
Intercompany note payable			—		65,500			—		(65,500	)		—
Accounts payable			10		314			—		—			324
Accounts payable-affiliates, net			44,060		(16,814	)		—		—			27,246
Accrued fuel, purchased power and transmission expense			484		26,115			—		—			26,599
Accrued interest			—		20,453			20,453		(20,453	)		20,453
Checks in excess of cash			581		5,284			—		—			5,865
Accrued liabilities			84		6,071			6		—			6,161

	Total current liabilities		45,219		106,923			85,959		(85,953	)		152,148
Long-term debt			—		—			738,000		—			738,000
Intercompany note payable			—		738,000			—		(738,000	)		—
Other long-term liabilities			—		5,600			—		—			5,600
Unrealized loss on SFAS No. 133			—		—			18		—			18

	Total liabilities		45,219		850,523			823,977		(823,953	)		895,766
MEMBERS’ EQUITY			192,222		248,265			445,513		(440,487	)		445,513

	Total liabilities and members’ equity	$	237,441	$	1,098,788		$	1,269,490	$	(1,264,440	)	$	1,341,279

(1)

All significant intercompany transactions have been eliminated in consolidation.

NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES
CONSOLIDATING STATEMENT OF OPERATIONS

For the Nine Months Ended September 30, 2001
(Unaudited)


					Louisiana
		Unrestricted,			Generating			South Central
		Non-			LLC			Generating
		Guarantor			(Bond			LLC			Eliminations			Consolidated
(Thousands of Dollars)		Subsidiaries			Guarantor)			(Bond Issuer)			(1)			Balance

Operating Revenues
	Revenues from wholly-owned operations	$	10,300		$	315,743		$	—		$	(12,731	)	$	313,312
Operating costs and expenses
	Cost of operations		18,282			212,739			1,197			(12,731	)		219,487
	Depreciation and amortization		1,617			20,296			—			—			21,913
	General and administrative expenses		434			4,439			274			—			5,147

Operating income			(10,033	)		78,269			(1,471	)		—			66,765
Other income/(expense)
	Other income, net		65			408			53,727			(53,727	)		473
	Equity in earnings of subsidiaries		—			—			14,056			(14,056	)		—
	Interest expense		—			(54,653	)		(53,727	)		53,727			(54,653	)

Net Income		$	(9,968	)	$	24,024		$	12,585		$	(14,056	)	$	12,585

NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES
CONSOLIDATING STATEMENT OF OPERATIONS

For the Three Months Ended September 30, 2001
(Unaudited)


					Louisiana
		Unrestricted,			Generating			South Central
		Non-			LLC			Generating
		Guarantor			(Bond			LLC			Eliminations			Consolidated
(Thousands of Dollars)		Subsidiaries			Guarantor)			(Bond Issuer)			(1)			Balance

Operating Revenues
	Revenues from wholly-owned operations	$	8,474		$	112,616		$	—		$	(10,905	)	$	110,185
Operating costs and expenses
	Cost of operations		17,138			89,118			(13,374	)		(10,905	)		81,977
	Depreciation and amortization		1,065			6,759			—			—			7,824
	General and administrative expenses		171			1,174			34			—			1,379

Operating income			(9,900	)		15,565			13,340			—			19,005
Other income/(expense)
	Other income, net		6			173			17,793			(17,793	)		179
	Equity in earnings of subsidiaries		—			—			(12,339	)		12,339			—
	Interest expense		—			(18,183	)		(17,793	)		17,793			(18,183	)

Net Income		$	(9,894	)	$	(2,445	)	$	1,001		$	12,339		$	1,001

(1)

All significant intercompany transactions have been eliminated in consolidation.

NRG SOUTH CENTRAL GENERATING LLC AND SUBSIDIARIES
CONSOLIDATING STATEMENT OF CASH FLOWS

For the Nine Months Ended September 30, 2001
(Unaudited)


						Louisiana
			Unrestricted			Generating			South Central
			Non-			LLC			Generating
			Guarantor			(Bond			LLC			Eliminations			Consolidated
(Thousands of Dollars)			Subsidiaries			Guarantor)			(Bond Issuer)			(1)			Balance

Cash Flows from operating activities:
Net income			$	(9,968	)	$	24,024		$	12,585		$	(14,056	)	$	12,585
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
	Depreciation and amortization			1,617			20,296			—			—			21,913
	Amortization of deferred finance costs			—			345			163			—			508
	Unrealized loss on energy contracts			—			—			1,197			—			1,197
	Distributions in excess of earnings			—			—			(14,056	)		14,056			—
	Changes in assets and liabilities:
		Accounts receivable		(18	)		11,537			—			—			11,519
		Inventory		(650	)		(15,198	)		—			—			(15,848	)
		Prepaid expenses		(160	)		(2,165	)		—			—			(2,325	)
		Accounts payable		(366	)		1,728			—			—			1,362
		Accounts payable-affiliates		4,119			(48,848	)		118			—			(44,611	)
		Accrued interest		—			(17,290	)		(18,301	)		18,288			(17,303	)
		Interest receivable		—			—			18,288			(18,288	)		—
		Accrued fuel and purchased power expense		(374	)		10,473			—			—			10,099
		Other current liabilities		6,029			4,729			6			—			10,764
		Changes in other assets and liabilities		—			13			—			—			13

Net cash provided by (used in) operating activities				229			(10,356	)		—			—			(10,127	)

Cash flows from investing activities:
	Capital expenditures			—			(2,654	)		—			—			(2,654	)
	Intercompany note receivable			—			—			(40,000	)		40,000			—
	Payment received on loan to affiliate			—			—			25,250			(25,250	)		—
	Investment in decommissioning fund			—			(443	)		—			—			(443	)
	Investment in projects			(229	)		—			(5,051	)		5,051			(229	)

Net cash (used in) provided by investing activities				(229	)		(3,097	)		(19,801	)		19,801			(3,326	)

Cash flows from financing activities:
	Contributions by members			—			5,051			5,051			(5,051	)		5,051
	Net proceeds/payments on revolver			—			40,000			40,000			(40,000	)		40,000
	Repayments of long-term borrowings			—			(25,250	)		(25,250	)		25,250			(25,250	)
	Deferred financing costs			—			(356	)		—			—			(356	)

Net cash provided by (used in) financing activities:				—			19,445			19,801			(19,801	)		19,445

Net increase in cash and cash equivalents				—			5,992			—			—			5,992
Cash and cash equivalents, beginning of Period				—			3,146			—			—			3,146

Cash and cash equivalents, end of Period			$	—		$	9,138		$	—		$	—		$	9,138

(1)

All significant intercompany transactions have been eliminated in consolidation.

Note 7-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.

Form A Agreements

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

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

Form B Agreements

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

Louisiana Generating charges the distribution cooperative a monthly specific delivery facility charge of approximately 1.75% of the depreciated net book value of the specific delivery facilities, including additional investment. The distribution cooperative may assume the right to maintain the specific delivery facilities and reduce the charge to 1.25% of the depreciated net book value of the specific delivery facilities. Louisiana Generating also charges the distribution cooperative its ratable share of 1.75% of the depreciated book value of common delivery facilities, which include communications, transmission and metering facilities owned by Louisiana Generating to provide supervisory control and date acquisition, and automatic control for customers.

For base supply, Louisiana Generating charges the distribution cooperative a demand charge, an energy charge and a fuel charge. The demand charge for each contract year is set forth in the agreement and is subject to increase for environmental legislation or occupational safety and health laws enacted after the effective date of the agreement. Louisiana Generating can increase the demand charge to the extent its cost of providing supplemental supply exceeds $400 per kilowatt (kW). The energy charge is fixed through 2004, and decreased slightly for the remainder of the contract term. The fuel charge is a pass-through of fuel and purchase 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 nine, Louisiana Generating will establish a rate equal to the ratable share of $18 million. The amount of the fund will be approximately $720,000. This fund will be used to offset the energy costs of the Form B distribution cooperatives which elected the fuel pass-through provision of the fuel charge, to the extent the cost of power exceeds $0.04 per kWh. Any funds remaining at the end of the term of the power supply agreement will be returned to Louisiana Generating.

Form C Agreements

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

The term of the Form C power supply agreement is for four years following the closing date of the acquisition of the Cajun facilities. However, three of the distribution cooperatives have entered into an amended and restated Form C power purchase agreement that extends the term of the agreement through March 31, 2014. A fourth distribution cooperative has entered into a similar amended and restated Form C agreement that extends the term of its agreement through March 31, 2009. Approval of these four agreements is pending at the FERC and the Louisiana Public Service Commission.

Louisiana Generating will charge the distribution cooperative a demand rate, a variable operation and maintenance charge and fuel charge. Louisiana Generating will not offer the distribution cooperatives which select the Form C agreement any new incentive rates, but will continue to honor existing incentive rates. At the end of the term of the agreement, the distribution cooperative is obligated to purchase the specific delivery facilities for a purchase price equal to the depreciated book value.

Louisiana Generating must contract for all transmission services required to serve the distribution cooperative and will pass through the costs of transmission service to the cooperative. Louisiana Generating is required to supply at its cost, without pass-through, control area services and ancillary services which transmission providers are not required to provide.

Louisiana Generating owns and maintains the substations and other facilities used to deliver energy and capacity to the distribution cooperative and charges the cooperative a monthly specific delivery facility charge for such facilities; any additions to, or new delivery facilities. The initial monthly charge is 1% of the value of all of the distribution cooperative’s specific delivery facilities. The cost of additional investment during the term of the agreement will be added to the initial value of the delivery facilities to calculate the monthly specific delivery facility charge.

Included in the amended and restated Form C agreements is a provision for an annual $250,000 Economic Development Contribution to be shared among the four Form C distribution cooperatives, beginning in April 2004 and extending through the end of the contract terms.

Other Power Supply Agreements

Louisiana Generating assumed Cajun Electric’s rights and obligations under two consecutive long-term power supply agreements with South Western Electric Power Company (SWEPCO), one agreement with South Mississippi Electric Power Association (SMEPA) and one agreement with Municipal Energy Agency of Mississippi (MEAM).

The SWEPCO Operating Reserves and Off-Peak Power Sale Agreement, terminates on December 31, 2007. The agreement requires Louisiana Generating to supply 100 megawatts (MW) of off-peak energy during certain hours of the day to a maximum of 292,000 megawatt-hours (MWh) per year and an additional 100 MW of operating reserve capacity and the associated energy within ten minutes of a phone request during certain hours to a

maximum of 43,800 MWh of operating reserve energy per year. The obligation to purchase the 100 MW of off-peak energy is contingent on Louisiana Generating’s ability to deliver operating reserve capacity and energy associated with operating reserve capacity. At Louisiana Generating’s request, it will supply up to 100 MW of non-firm, 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 10 minutes of a phone request. In addition, SWEPCO is granted the right to purchase up to 21,900 MWh/year of operating reserve energy.

The SMEPA Unit Power Sale Agreement is effective through May 31, 2009, unless terminated following certain regulatory changes, changes in fuel costs or destruction of the Cajun facilities. The agreement requires Louisiana Generating to provide 75 MW of capacity and the associated energy from Big Cajun II, Unit 1 and an option for SMEPA to purchase additional capacity and associated energy if Louisiana Generating determines that it is available, in 10 MW increments, up to a total of 200 MW. SMEPA is required to schedule a minimum of 25 MW plus 37% of any additional capacity that is purchased. The capacity charge is fixed through May 31, 2004, and increases for the period June 1, 2004 through May 31, 2009 including transmission costs to the delivery point and any escalation of expenses. The energy charge is 110% of the incremental fuel cost for Big Cajun II, Unit 1.

The MEAM Power Sale Agreement is effective through May 31, 2010 with an option for MEAM to extend through September 30, 2015 upon five years advance notice. The agreement requires Louisiana Generating to provide 20 MW of firm capacity and associated energy with an option for MEAM to increase the capacity purchased to a total of 30 MW upon five years advance notice. The capacity charge is fixed. The operation and maintenance charge is a fixed amount which escalates at 3.5% per year. There is a transmission charge which varies depending upon the delivery point. The price for energy associated with the firm capacity is 110% of the incremental generating cost to Louisiana Generating and is adjusted to include transmission losses to the delivery point.

Coal Supply Agreement

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

Coal Transportation Agreement

Louisiana Generating entered into a coal transportation agreement with Burlington Northern and Santa Fe Railway and American Commercial Terminal. This agreement provides for the transport of all of the coal requirements of Big Cajun II from the mines in Wyoming to Big Cajun II.

Transmission and Interconnection Agreements

Louisiana Generating assumed Cajun Electric’s existing transmission agreements with Central Louisiana Electric Company, SWEPCO; and Entergy Services, Inc., acting as agent for Entergy Arkansas, Inc., Entergy Gulf States, Entergy Louisiana, Inc., Entergy Mississippi, Inc., and Entergy New Orleans, Inc. On June 11, 2002, Entergy Services, Inc. submitted for filing at the FERC an Interconnection and Operating Agreement between Louisiana Generating (for Big Cajun II) and Entergy Gulf States, Inc. and a similar Interconnection and Operating Agreement between Louisiana Generating (for Big Cajun Peaking) and Entergy Gulf States, Inc. to be effective the day after filing. The Cajun facilities are connected to the transmission system of Entergy Gulf States and power is delivered to the distribution cooperative at various delivery points on the transmission systems of Entergy Gulf States, Entergy Louisiana, Central Louisiana Electric Company and SWEPCO. Louisiana Generating also assumed from Cajun Electric 20 interchange and sales agreements with utilities and cooperatives, providing access to a 12 state area.

Guarantees

The Company is directly liable for the obligations of certain of its subsidiaries pursuant to guarantees relating

to certain of their operating obligations. In addition, in connection with the purchase and sale of fuel, emission credits and power generation products to and from third parties with respect to the operation of some of the Company’s generation facilities in the United States, the Company may be required to guarantee a portion of the obligations of certain of its subsidiaries. As of September 30, 2002, the Company’s obligations pursuant to its guarantees of the performance of its subsidiaries totaled approximately $77.2 million.

Note 8 — Special Charges

The Company has a turbine generator, held at New Roads, that has been held for sale since its acquisition. Based on unsuccessful efforts to sell the turbine at a price that would recover its carrying value, the Company determined that the fair value of the turbine had declined. Accordingly, the Company recorded a charge of $12.2 million in the third quarter to write down the asset held for sale to its estimated fair value which is based on the scrap value of the turbine.

Note 9 — Write Down of Equity Method Investments

In September 2002, NRG Energy agreed to transfer its indirect 50% interest in SRW Cogeneration LP (SRW), to its partner in SRW, Conoco, Inc. in consideration for Conoco’s agreement to terminate or assume all of the obligations of NRG Energy in relation to SRW. SRW owns a cogeneration facility in Orange County, Texas. The Company recorded a charge of approximately $48 million during the quarter ended September 30, 2002 to write down the carrying value of its investment due to the pending sale. The sale closed on November 5, 2002.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

RESULTS OF OPERATIONS

FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2002 COMPARED TO THE THREE MONTHS ENDED SEPTEMBER 30, 2001


					Three Months Ended					Three Months Ended
					September 30, 2002					September 30, 2001
								% of					% of
(Millions of Dollars)								revenue					revenue			Increase/(decrease)

Operating revenue and equity earnings					$	104.1		100.0	%	$	110.2			100.0	%	$	(6.1	)	(5.5	%)


Coal					$	33.4		32.1	%	$	36.5			33.1	%		(3.1	)	(8.5	%)
Natural gas						6.4		6.1	%		4.0			3.6	%		2.4		60.0	%
Other fuels						0.2		0.2	%		0.2			0.2	%		0.0		(0.0	%)
Purchased energy						19.0		18.3	%		41.8			37.9	%		(22.8	)	(54.5	%)

		Fuel expense			$	59.0		56.7	%	$	82.5			74.9	%	$	(23.5	)	(28.5	%)


Labor and benefits					$	2.6		2.5	%	$	3.1			2.8	%	$	(0.5	)	(16.1	%)
Parts and supplies						4.7		4.5	%		6.6			6.0	%		(1.9	)	(28.8	%)
Property taxes						1.8		1.7	%		3.3			3.0	%		(1.5	)	(45.5	%)

	Operations and maintenance				$	9.1		8.7	%	$	13.0			11.8	%	$	(3.9	)	(30.0	%)


Unrealized SFAS No. 133 loss/(gain)					$	0.0		0.0	%	$	(13.5	)		(12.3	%)	$	13.5		(100.0	%)

				Cost of operations	$	68.1		65.4	%	$	82.0			74.4	%	$	(13.9	)	(17.0	%)


Depreciation and amortization					$	9.3		8.9	%	$	7.8			7.1	%	$	1.5		19.2	%
General and administrative						2.0		1.9	%		1.4			1.3	%		0.6		42.9	%
Special charges						12.2		11.7	%		—			0.0	%		12.2		—
Write down of equity method investments						48.4		46.5	%		—			0.0	%		48.4		—
Interest						19.1		18.3	%		18.2			16.5	%		0.9		5.0	%
Other (income) expense						(0.2	)	(0.1	%)		(0.2	)		(0.2	%)		0.0		—

			Net Income		$	(54.8	)	(52.6	%)	$	1.0			0.9	%	$	(55.8	)	(5,580.0	%)

Operating Revenues

The decrease in revenues for the three months ended September 30, 2002 compared to the same period in 2001 is primarily due to lower merchant power sales prices as a result of an adverse change in overall market conditions from 2001 to 2002. Additionally, less electricity was produced and sold during this quarter compared to the same period in 2001.

Cost of Operations

The decrease in the cost of operations for the three months ended September 30, 2002 as compared to the same period in 2001 is primarily attributed to a decrease in purchased energy costs. The Company buys electricity to fulfill its obligation to its customers if it is more economical than producing electricity. The adverse change in overall market conditions from 2001 to 2002 greatly decreased the demand for power as well as the cost per kilowatt hour.

Depreciation and Amortization

The increase in depreciation and amortization expense for the three months ended September 30, 2002 compared to the same period in 2001 is due to the increase in property, plant, and equipment during 2002 resulting from the completion of the Big Cajun Peaking, Sterlington and Bayou Cove facilities.

General and Administrative Expense

The increase in general and administrative expense for the three months ended September 30, 2002 compared to the same period in 2001 is primarily due to non capitalized internal labor costs associated with the Bayou Cove plant, which began construction in November 2001.

Special Charges

The Company has a turbine generator, held at the Company’s New Roads Holdings subsidiary, that has been held for sale since its acquisition. Based on unsuccessful efforts to sell the turbine at a price that would recover its carrying value, the Company determined that the fair value of the turbine had declined. Accordingly, the Company recorded a charge of $12.2 million in the third quarter to write down the asset held for sale to its estimated fair value, which is based on the scrap value of the turbine.

Write Down of Equity Method Investments

Interest Expense

The increase in interest expense for the three months ended September 30, 2002 compared to the same period in 2001 is due to the increase in debt, primarily at the Bayou Cove facility, during 2002.

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2002 COMPARED TO THE NINE MONTHS ENDED SEPTEMBER 30, 2001


			Nine months ended						Nine months ended
			September 30, 2002						September 30, 2001
						% of						% of
(Millions of Dollars)						revenue						revenue				Increase/(decrease)

Operating revenue and equity earnings			$	292.9			100.0	%	$	313.3			100.0	%	$	(20.4	)	(6.5	%)


Coal			$	99.4			33.9	%	$	101.4			32.4	%		(2.0	)	(2.0	%)
Natural gas				9.4			3.2	%		5.4			1.7	%		4.0		74.1	%
Other fuels				0.6			0.2	%		0.8			0.3	%		(0.2	)	(25.0	%)
Purchased energy				53.6			18.3	%		77.0			24.6	%		(23.4	)	(30.4	%)

	Fuel expense		$	163.0			55.7	%	$	184.6			58.9	%	$	(21.6	)	(11.7	%)


Labor and benefits			$	11.4			3.9	%	$	11.5			3.7	%	$	(0.1	)	(0.9	%)
Parts and supplies				15.2			5.2	%		14.9			4.8	%		0.3		2.0	%
Property taxes				1.3			0.4	%		7.3			2.3	%		(6.0	)	(82.2	%)

	Operations and maintenance		$	27.9			9.5	%	$	33.7			10.8	%	$	(5.8	)	(17.2	%)


Unrealized SFAS No. 133 loss			$	0.3			0.1	%	$	1.2			0.4	%	$	(0.9	)	(75.0	%)

		Cost of operations	$	191.2			65.3	%	$	219.5			70.1	%	$	(28.3	)	(12.9	%)


Depreciation and amortization			$	27.2			9.3	%	$	21.9			7.0	%	$	5.3		24.2	%
General and administrative				6.6			2.3	%		5.1			1.6	%		1.5		29.4	%
Special charges				12.2			4.2	%		—			0.0	%		12.2		—
Write down of equity method investments				48.4			16.5	%		—			0.0	%		48.4		—
Interest				54.3			18.5	%		54.7			17.5	%		(0.4	)	(0.7	%)
Other (income) expense				(0.5	)		(0.2	%)		(0.5	)		(0.2	%)		0.0		(0.0	%)

		Net Income	$	(46.5	)		(15.9	%)	$	12.6			4.0	%	$	(59.1	)	(469.0	%)

Operating Revenues

The decrease in revenues for the nine months ended September 30, 2002 compared to the same period in 2001 is primarily due lower merchant power sales prices as a result of an adverse change in overall market conditions from 2001 to 2002. Additionally, less electricity was produced and sold during the nine months ended September 30, 2002, compared to the same period in 2001.

Cost of Operations

The decrease in the cost of operations for the nine months ended September 30, 2002 compared to the same period in 2001 is primarily attributed to a decrease in purchased energy costs.

The Company buys electricity to fulfill its obligations to customers, if it is more economical than producing electricity. The adverse change in overall market conditions from 2001 to 2002 greatly decreased the cost per kilowatt hour. Additionally, coal expense decreased due to a favorable legal settlement related to the coal supply agreement with Triton Coal.

Depreciation and Amortization

The increase in depreciation and amortization expense for the nine months ended September 30, 2002 compared to the same period in 2001 is due to the current period being the first full period of depreciation charges on projects place in service in 2001. The increase in depreciation and amortization expense is primarily related to the Big Cajun Peaking, Sterlington and Bayou Cove facilities.

General and Administrative Expense

The increase in general and administrative expense for the nine months ended September 30, 2002 compared to the same period in 2001 is primarily due to non capitalized internal labor costs associated with the Bayou Cove plant, which began construction in November 2001.

Special Charges

The Company has a turbine generator, held at New Roads Holdings subsidiary, that has been held for sale since its acquisition. Based on unsuccessful efforts to sell the turbine at a price that would recover its carrying value the company determined that the fair value of the turbine had declined. Accordingly, the company recorded a charge of $12.2 million in the third quarter to write down the asset held for sale to its estimated fair value, which is based on the scrap value of the turbine.

Write down of Equity Method Investments

Interest Expense

The increase in interest expense for the nine months ended September 30, 2002 compared to the same period in 2001 is due to the increase in debt, primarily at the Bayou Cove subsidiary, during 2002. This additional debt is the result of the financing on the three Peaking Power Plants: Bayou Cove, Big Cajun Peaking and Sterlington.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The Company management’s discussion and analysis of its financial condition and results of operations are based upon the Company’s consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements and related disclosures in compliance with generally accepted accounting principles requires the application of appropriate technical accounting rules and guidance as well as the use of estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. These judgments, in and of themselves, could materially impact the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment also may have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies have not changed.

On an ongoing basis, the Company evaluates its estimates, utilizing historic experience, consultation with experts and other methods the Company considers reasonable. In any case, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

Refer to Item 8 Note 2 of the consolidated financial statements of NRG South Central Generating LLC Form 10-K for the year ended December 31, 2001 for additional discussion regarding NRG South Central’s accounting policies and estimates.

LIQUIDITY AND CAPITAL RESOURCES

As discussed earlier, NRG Energy is not making any payments of principal and interest on its corporate level debt and neither NRG Energy nor certain of its subsidiaries, including NRG South Central, are making payment of principal and interest on publicly held bonds and certain project level credit facilities. This failure to pay, coupled with past and anticipated proceeds from the sales of projects, has provided the Company with adequate liquidity to meet its day-to-day operating costs. However, there can be no assurance that holders of the Company indebtedness on which interest and principal are not being paid will not seek to enforce their remedies, which would likely lead to NRG South Central Generating seeking relief under bankruptcy laws.

The Company and its majority-owned subsidiaries have historically obtained cash from operations, issuance of debt securities contributions and advances from NRG Energy and affiliates, and borrowings under credit facilities. The Company and its subsidiaries have used these funds to finance operations, service debt obligations, fund the acquisition, development and construction of generation facilities, finance capital expenditures and meet other cash and liquidity needs.

In December 2001, Moody’s placed NRG Energy’s long-term senior unsecured debt rating on review for downgrade. In response to this threat to NRG Energy’s investment grade rating, on February 17, 2002, Xcel Energy announced a financial improvement plan for NRG Energy, which included an initial step of acquiring 100% of NRG through a tender offer to exchange all of the outstanding shares of NRG Energy common stock for Xcel Energy common shares. In addition, the plan included financial support to NRG Energy from Xcel Energy; marketing certain NRG Energy generating assets for possible sale; canceling and deferring capital spending for NRG Energy projects; and combining certain of NRG Energy’s functions with Xcel Energy’s system and organization. On June 3, 2002, Xcel Energy completed its exchange offer for the 26% of NRG Energy’s shares that had been previously publicly held. Xcel Energy offered NRG Energy shareholders 0.50 shares of Xcel Energy common stock for each outstanding share of NRG Energy common stock, representing a $650 million purchase price. During 2002, Xcel Energy has provided NRG Energy with $500 million of cash infusions. Throughout this period of time, Xcel Energy was in discussions with credit agencies and believed that its actions would be sufficient to avoid a downgrade of NRG Energy’s credit rating.

However, even with NRG Energy’s efforts to avoid a downgrade, unexpectedly on July 26, 2002, Standard & Poors’ downgraded NRG Energy’s senior unsecured bonds below investment grade, and three days later Moody’s Investors’ Services also downgraded NRG Energy’s senior unsecured debt rating below investment grade. Over the next few months NRG senior unsecured debt, as well as the secured NRG Northeast Generating LLC bonds and the secured NRG South Central Generating LLC bonds, were downgraded multiple times. After NRG Energy failed to make the payment obligations due under certain unsecured bond obligations on September 16, 2002, both Moody’s and S&P lowered their ratings on NRG Energy’s unsecured bonds once again.

The debt agreements of NRG South Central generally restrict its ability to pay dividends, make distributions or otherwise transfer funds to NRG Energy. As of September 30, 2002, NRG South Central did not meet the minimum debt service coverage ratios required to make payments to NRG Energy and NRG South Central in default on its credit agreements.

NRG South Central Generating is also precluded from making payments to NRG Energy due to unfunded debt service reserve accounts. Prior to the NRG Energy downgrades, the debt service reserve accounts were funded with letters of guarantee from the parent company. Following the downgrade, these accounts were required to be funded with cash within five to thirty days following the downgrade. The accounts were not funded with cash from NRG Energy, and after allowing for respective cure periods, as such create an event of default and allows the lenders to accelerate the project financing.

Starting in August 2002, NRG Energy engaged in the preparation of a comprehensive business plan and forecast. The business plan detailed the strategic merits and financial value of NRG Energy’s projects and operations. It also anticipates that NRG Energy will function independently from Xcel Energy and thus all plans and efforts to combine certain functions of the companies were terminated. NRG Energy utilized independent electric revenue forecasts from an outside energy markets consulting firm to develop forecasted cash flow included in the business plan. Management concluded that the forecasted free cash flow available to NRG Energy after servicing project-level obligations will be insufficient to service recourse debt obligations. Based on this information and in consultation with Xcel Energy and its financial advisor, NRG Energy prepared and submitted a restructuring plan on November 4, 2002 to various lenders, bondholders and other creditor groups (collectively, “NRG Energy’s Creditors”) of NRG Energy and its subsidiaries. The restructuring plan is expected to serve as a basis for negotiations with NRG Energy’s Creditors in a financially-restructured NRG Energy and, among other things, proposes (i) holders of secured (project-level) debt would either (a) have their debt reinstated with agreed modifications or (b) receive the collateral securing such debt and a claim or claims to the extent such debt is under-secured; (ii) holders of unsecured debt, holders of secured recourse claims against NRG Energy, and holders of other general unsecured claims against NRG Energy would receive a pro rata share of (a) an aggregate of $500 million of junior secured debt of reorganized NRG Energy and (b) 95% of the common equity of reorganized NRG Energy; and (iii) holders of project-level general unsecured claims that are non-recourse to NRG Energy would receive a pro rata share of the remaining 5% of the common equity of reorganized NRG Energy.

Under the proposed plan, owned assets with unfunded debt service reserve accounts would be funded at the project level over time with operating cash from the projects as it becomes available. NRG South Central has approximately $46.6 million of unfunded debt service reserve commitments.

As of October 31, 2002, the Company had cash and cash equivalents of approximately $75 million.

If NRG Energy files under Chapter 11, it is likely that NRG Energy would also file certain wholly-owned subsidiaries, which may include the Company.

Cash Flows


	For the nine months ended
	September 30,
(Thousands of Dollars)	2002		2001

Net cash provided by/(used in) operating activities	$	61,591	$	(10,127	)

Net cash provided by operations increased during the nine months ended September 30, 2002 compared to the same period in 2001. The most significant changes in working capital related to increases in Accounts Payable, Accounts Payable — Affiliate, and Accrued Interest during the current period, offset in part by a decrease in Accrued Fuel and Purchased Power Expense.


	For the nine months ended
	September 30,
(Thousands of Dollars)	2002			2001

Net cash used in investing activities	$	(58,409	)	$	(3,326	)

Net cash used in investing for the nine months ended September 30, 2002 increased in comparison to the same period in 2001. The increase is due to increases in capital expenditures and restricted cash in the current period.


	For the nine months ended
	September 30,
(Thousands of Dollars)	2002			2001

Net cash (used in)/provided by financing activities	$	(6,390	)	$	19,445

Net cash used in financing increased from the same period in 2001. The increase is primarily due to repayments of the revolver loan and long-term borrowings.

CAPITAL COMMITMENTS

Prospective Capital Requirements

The Company estimates $8 million and $15 million in capital spending for the period from October 21 through December 31, 2002, and for calendar year 2003, respectively. These amounts include the cost of capital improvements, minor refurbishments, and expansions of projects in operation. The Company plans to fund these liquidity needs with cash on hand and operating cash from generating assets. Current financial plans estimate cash from operations of $35 million for 2003.

The Company's capital expenditure program is subject to continuing review and modification. Actual expenditures may differ from these estimates.

Contractual obligations and commercial commitments


	Payments due by period as of September 30, 2002

(Thousands of Dollars)	Total		short term		1-3 years		4-5 years		after 5 years

Long term debt	$	858,103	$	858,103	$	—	$	—	$	—
Total contractual cash obligations	$	858,103	$	858,103	$	—	$	—	$	—


	Amount of commitment expiration period as of September 30, 2002
	Total amounts
(Thousands of Dollars)	committed		short term		1-3 years		4-5 years		after 5 years

Guarantees	$	77,200	$	64,200	$	—	$	—	$	13,000
Total commercial commitments	$	77,200	$	64,200	$	—	$	—	$	13,000

Other Contingencies

EWG Status for Big Cajun Peaker

In April 2002, NRG Energy discovered that filings with the Federal Energy Regulatory Commission (FERC) to exempt NRG Energy’s Big Cajun Peaking facility in Louisiana from regulation by the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act (PUHCA), and to sell power from the facility at market-based rates, had not been made. NRG Energy made those filings on April 17, 2002 and has discussed the situation with FERC and the SEC. While NRG Energy does not expect any material legal or regulatory action to be taken by those agencies, the failure to have made these filings could be viewed as an event of default under certain of NRG Energy’s debt facilities, including its $2 billion construction and acquisition revolving credit facility and $1 billion unsecured corporate revolving line of credit. Accordingly, NRG Energy sought and has received from its construction and acquisition facility lenders a waiver of any event of default occurring as a result of Big Cajun Peaking Power’s failure to file for exemption from regulation under PUHCA, and has sought and received from its corporate revolver lenders an amendment to its corporate revolving line of credit to provide that such failure to obtain or maintain exemption from regulation under PUHCA will not cause an event of default under that facility. While the construction and acquisition revolver waiver and the corporate revolver amendment were being discussed and finalized with its lenders, NRG Energy did not borrow under either of these credit facilities. The waiver under the construction and acquisition facility continues indefinitely unless a default arising out of any possible PUHCA violation occurs. On September 20, 2002, FERC issued its letter order finding Big Cajun Peaking to be an exempt wholesale generator as defined in Section 32 of PUHCA effective as of April 17, 2002.

DERIVATIVE INSTRUMENTS

Derivative Instruments

The tables below disclose the derivative activities that include non-exchange traded contracts accounted for at fair value. Specifically, these tables disaggregate realized and unrealized changes in fair value; identifies changes

in fair value attributable to changes in valuation techniques; disaggregates estimated fair values at September 30, 2002 based on whether fair values are determined by quoted market prices or more subjective means; and indicates the maturities of contracts at September 30, 2002.

Derivative Activity


(Thousands of dollars)	Gains/(Losses)

Fair Value of contracts outstanding at the beginning of the period	$	(255	)
Contracts realized or otherwise settled during the period		(25	)
Fair value of new contract when entered into during the period		—
Changes in fair values attributable to changes in valuation techniques		—
Other changes in fair values		10

Fair value of contracts outstanding at the end of the period	$	(270	)

Sources of Fair Value


	Fair Value of Contracts at Period End
										Total
Gains/(Losses)	Maturity			Maturity		Maturity		Maturity		Fair
(Thousands of dollars)	Less than 1 Year			1-3 Years		4-5 Years		in excess of 5 Years		Value

Prices actively quoted	$	—		$	—	$	—	$	—	$	—
Prices provided by other external sources		—			—		—		—		—
Prices based on models & other valuation methods		(270	)		—		—		—		(270	)

	$	(270	)	$	—	$	—	$	—	$	(270	)

NEW ACCOUNTING PRONOUNCEMENTS

In June 2001, the Financial Accounting Standards Board (the FASB) issued Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets (SFAS No. 142). SFAS No. 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized but instead be tested for impairment in accordance with SFAS No. 121, Accounting for the Impairment of Long-lived Assets and for Long-lived Assets to Be Disposed Of (SFAS No. 121). Goodwill will no longer be amortized to comply with the provisions of SFAS No. 142. Instead, goodwill and intangible assets that will not be amortized should be tested for impairment annually and on an interim basis if an event occurs or a circumstance changes between annual tests that may reduce the fair value of a reporting unit below its carrying value. An impairment test is required to be performed within nine months of the date of adoption, and the first annual impairment test must be performed in the year the statement is initially adopted. The Company has adopted the provisions of SFAS No. 142 effective January 1, 2002. No impairments on assets were recorded upon adopting SFAS 142 on January 1, 2002.

In June 2001, FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations (SFAS No. 143). This statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. 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. SFAS No. 143 is effective for financial statements issued for fiscal years beginning after June 15, 2002. NRG South Central has not completed its analysis of SFAS No. 143.

In October 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (SFAS No. 144). This statement addresses financial accounting and reporting for the impairment or disposal of long-lived assets. SFAS No. 144 retains and expands upon the fundamental provisions of existing guidance related to the recognition and measurement of the impairment of long-lived assets to be held and used and the measurement of long-lived assets to be disposed of by sale. Generally, the provisions of SFAS No. 144 are effective for financial statements issued for fiscal years beginning after December 15, 2001. The Company has adopted SFAS No. 144 effective January 1, 2002. See Footnote 8 to the Consolidated Financial Statements and the Results of Operations in Management’s Discussion and Analysis for information about asset impairments during the quarter ended September 30, 2002.

In April 2002, FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections (SFAS No. 145), that supercedes previous guidance for the reporting of gains and losses from extinguishment of debt and accounting for leases, among other things. SFAS No. 145 requires that only gains and losses from the extinguishment of debt that meet the requirements for classification as “Extraordinary Items,” as prescribed in Accounting Practices Board Opinion No. 30, should be disclosed as such in the financial statements. Previous guidance required all gains and losses from the extinguishment of debt to be classified as “Extraordinary Items.” This portion of SFAS No. 145 is effective for fiscal years beginning after May 15, 2002, with restatement for prior periods required. In addition, SFAS No. 145 amends SFAS No. 13, Accounting for Leases (SFAS No. 13), as it relates to accounting by a lessee for certain lease modifications. Under SFAS No. 13, if a capital lease is modified in such a way that the change gives rise to a new agreement classified as an operating lease, the assets and obligation are removed, a gain or loss is recognized and the new lease is accounted for as an operating lease. Under SFAS No. 145, capital leases that are modified so the resulting lease agreement is classified as an operating lease are to be accounted for under the sale-leaseback provisions of SFAS No. 98, Accounting for Leases. These provisions of SFAS No. 145 are effective for transaction occurring after May 15, 2002. SFAS No. 145 will be applied as required. Adoption of SFAS No. 145 is not expected to have a material impact on the Company.

In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” (SFAS No. 146). SFAS No. 146 addresses financial reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force (EITF) Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” SFAS No. 146 applies to costs associated with an exit activity that does not involve an entity newly acquired in a business combination or with a disposal activity covered by SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” The provisions of SFAS 146 are effective for exit or disposal activities that are initiated after December 31, 2002, with early application encouraged. The Company is not aware of any exit or disposal activities for which the accounting standard will apply at this time.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The Company is exposed to market risks, including changes in commodity prices and interest rates, and credit risk as disclosed in Management’s Discussion and Analysis in its annual report on Form 10-K for the year ended December 31, 2001. There have been no material changes as of September 30, 2002 to the market risk disclosures presented as of December 31, 2001.

Item 4. Controls and Procedures

NRG Energy’s Chief Operating Officer and Chief Financial Officer have evaluated the effectiveness of the Company's disclosure controls and procedures (as such term is defined in Rules 13a-14(c) and 15d-14(c)) under the Securities Exchange Act of 1934, as amended (Exchange Act) as of a date within 90 days prior to the filing date of this quarterly report (Evaluation Date). Based on such evaluation, such officers have concluded that, as of the Evaluation Date, the Company's disclosure controls and procedures are effective in alerting them on a timely basis to material information relating to the Company (including its consolidated subsidiaries) required to be included in the Company's periodic filings under the Act.

Since the Evaluation Date, there have not been any significant changes in the Company’s internal controls or in other factors that could significantly affect such controls.

Part II — OTHER INFORMATION

Item 1. Legal Proceedings

On July 5, 2001, PG&E Energy Trading Power, L.P. (PGET), a subsidiary of PG&E Corporation, filed a demand for arbitration with the American Arbitration Association stating a claim against SRW Cogeneration Limited Partnership (SRW). SRW is a Delaware limited partnership that owns and operates an approximately 420

MW natural gas-fired cogeneration plant at the DuPont Company’s Sabine River Works petrochemical facility near Orange, Texas. SRW is 50% owned by Sabine River Works LP and Sabine River Works GP. The remaining 50% of SRW is owned by subsidiaries of Conoco Inc.

PGET and SRW had entered into a Tolling Agreement under which PGET was to provide gas to SRW for use in generating electricity, a portion of which would be delivered to PGET. Under the Tolling Agreement, both parties provided a corporate guarantee for the performance of their respective obligations under the agreement. PGET’s corporate guarantor was its ultimate parent, PG&E Corporation, whose credit rating dropped from the level required to be maintained under the terms of the Tolling Agreement, and SRW exercised its right to terminate the Tolling Agreement.

PGET is challenging that termination. In its arbitration petition, it is claiming damages for SRW’s failure to deliver power to PGET pursuant to the Tolling Agreement and for SRW’s failure to accept natural gas from PGET pursuant to the Tolling Agreement. PGET alleges that the amount in dispute is in excess of $100 million. SRW considers that it properly terminated the Tolling Agreement in full accordance with the Tolling Agreement’s express and unambiguous terms, and that PGET is not entitled to the relief sought. SRW has counterclaimed for damages in excess of $100,000 and will continue vigorously to defend this claim.

On May 6, 2002, PGET agreed to dismiss with prejudice their demand for arbitration with the American Arbitration Association and in return SRW agreed to dismiss their counterclaim against PGET for damages.

There are no other material legal proceedings pending, to which NRG South Central or any of its subsidiaries are a party. There are no material legal proceedings to which an officer or director is a party or has a material interest adverse to NRG South Central or its subsidiaries.

There are no material administrative or judicial proceedings arising under environmental quality or civil rights statutes pending or known to be contemplated by governmental agencies to which the Company is or would be a party.

Item 3. Defaults on Senior Securities

The Company has identified the following material defaults with respect to the indebtedness of the Company and its significant subsidiaries:

$500 million of 8.962% Series A-1 Secured Notes due in 2016 issued by the Company

• Failure to make $20.2 million interest and $12.75 million principal payment

• Failure to fund debt service reserve account

$300 million of 9.479% Series B-1 Secured Secured bonds due 2024 issued by the Company

• Failure to make $14.2 million interest payment

• Failure to fund debt service reserve account

$325 million Series A floating rate Senior Secured Bonds due in 2019 issued by NRG Peaker Finance Company LLC (which is not a subsidiary of the Company, but certain of the assets pledged for this financing are owned by Bayou Cove Peaking LLC, Big Cajun I Peaking LLC and NRG Sterlington Power LLC, indirect, wholly-owned subsidiaries of the Company)

• Failure to remove liens placed on one of the project company assets

• A cross default resulting from failure by NRG Energy to make payments of principal, interest and other amounts due on NRG Energy’s debt for borrowed money in excess of $50 million in the aggregate

Item 6. Exhibits and Reports on Form 8-K


(A)		Exhibits

		99.1 Officers’ Certification

(B)		Reports on Form 8-K

On October 4, 2002, the Company filed a Form 8-K reporting under Item 5 — Other Events.

On October 1, 2002, NRG Energy announced the end of the fifteen-day grace period for payment of $47 million in combined principal and interest payments on the NRG South Central LLC (a wholly owned subsidiary of NRG Energy) 8.962 percent, series A-1 senior secured bonds due 2016 and 9.479% series B-1 senior secured bonds due 2024.

On October 24, 2002, the Company filed a Form 8-K reporting under Item 5 — Other Events.

On October 18, 2002, NRG Energy announced that it had reached an agreement with certain of its bank lenders to extend until November 15, the deadline by which it must post approximately $1 billion of cash collateral in connection with certain bank loan agreements. NRG Energy also announced the filing by The Shaw Group Inc. of an involuntary petition for liquidation of LSP-Pike Energy, LLC under Chapter 7 of the U.S. Bankruptcy Code. Shaw, the contractor for NRG Energy’s Pike power plant construction project in Holmesville, Mississippi, also filed suit against NRG Energy and Xcel Energy alleging claims connected with the Pike project.

Cautionary Statement Regarding Forward-Looking Information

The information presented in this Form 10-Q includes forward-looking statements in addition to historical information. These statements involve known and unknown risks and relate to future events, or projected business results. In some cases forward-looking statements may be identified by their use of such words as “may,” “expects,” “plans,” “anticipates,” “believes,” and similar terms. Forward-looking statements are only predictions, and actual results may differ materially from the expectations expressed in any forward-looking statement. While the Company believes that the expectations expressed in such forward-looking statements are reasonable, we can give no assurances that these expectations will prove to have been correct. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:


•		NRG Energy’s ability to reach agreements with its lenders and creditors to restructure debt and delay the funding of collateral required following NRG Energy’s, and the Company’s, ratings downgrades by Moody’s and Standard & Poor’s;
•		NRG Energy’s ability to sell assets in the amounts and on the time table assumed;
•		General economic conditions including inflation rates and monetary exchange rate fluctuations; the risk of a significant slowdown in growth in the U.S. economy or risk in delay in growth recovery in the U.S. as a consequence of the September 11, 2001 terrorist attacks and other factors;
•		Trade, monetary, fiscal, taxation, and environmental policies of governments, agencies and similar organizations in geographic areas where the Company has financial interest;
•		Customer business conditions including demand for their products or services and supply of labor and materials used in creating their products and services;
•		Financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board, the Securities and Exchange Commission, the Federal Energy Regulatory Commission and similar entities with regulatory oversight;
•		Factors affecting the availability or cost of capital, such as changes in: interest rates; market perceptions of the power generation industry, the Company or any of its subsidiaries; or credit ratings;
•		Factors affecting power generation operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel, or gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; or electric transmission or gas pipeline system constraints;
•		Employee workforce factors including loss or retirement of key executives, collective bargaining agreements with union employees, or work stoppages;
•		Volatility of energy process in a deregulated market environment;
•		Increased competition in the power generation industry;
•		Cost and other effects of legal and administrative proceedings, settlements, investigations and claims;
•		Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets;
•		Factors associated with various investments including competition, operating risks, dependence on certain suppliers and customers, and environmental and energy regulations;
•		Other business or investment considerations that may be disclosed from time to time in the Company’s Securities and Exchange Commission filings or in other publicly disseminated written documents.

The Company undertakes no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors that could cause the Company’s actual results to differ materially from those contemplated in any forward-looking statements included in this Form 10-Q should not be construed as exhaustive.

Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	NRG South Central Generating LLC
	(Registrant)

	/s/ RICHARD C. KELLY Richard C. Kelly, President

	/s/ C. ADAM CARTE C. Adam Carte, Treasurer (Principal Financial Officer)

Date: November 18, 2002

CERTIFICATIONS

I, Richard C. Kelly, certify that:

1. I have reviewed this quarterly report on Form 10-Q of NRG South Central Generating LLC;

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.


Dated: November 18, 2002

/s/ RICHARD C. KELLY Richard C. Kelly, President

CERTIFICATIONS

I, C. Adam Carte, certify that:

d) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

e) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

f) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

c) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

d) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and


Dated: November 18, 2002

/s/ C. ADAM CARTE C. Adam Carte, Treasurer

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	•		Failure to make $20.2 million interest and $12.75 million principal payment

	•		Failure to fund debt service reserve account

	•		Failure to make $14.2 million interest payment

	•		Failure to fund debt service reserve account

	•		Failure to remove liens placed on one of the project company assets

	•		A cross default resulting from failure by NRG Energy to make payments of principal, interest and other amounts due on NRG Energy’s debt for borrowed money in excess of $50 million in the aggregate

	1.		I have reviewed this quarterly report on Form 10-Q of NRG South Central Generating LLC;

	2.		Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

	3.		Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

	4.		The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

	a)		designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

	b)		evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

	c)		presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

	a)		all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

	b)		any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and