Louisiana Generating LLC
Financial Statements
For the Years Ended December 31, 2001 and 2000

		Page(s)
Report of Independent Accountants		1
Financial Statements:
	Balance Sheet at December 31, 2001 and 2000		2
	Statement of Operations for the year ended December 31, 2001 and the period from March 30, 2000 (inception) through December 31, 2000		3
	Statement of Cash Flows for the year ended December 31, 2001 and the period from March 30, 2000 (inception) through December 31, 2000		4
	Statement of Members' Equity for the year ended December 31, 2001 and the period from March 30, 2000 (inception) through December 31, 2000		5
Notes to Financial Statements		6-17

In our opinion, the accompanying balance sheet and the related statements of operations, of member's equity and of cash flows present fairly, in all material respects, the financial position of Louisiana Generating LLC at December 31, 2001 and 2000, and the results of its operations and its cash flows for the year ended December 31, 2001 and the period from March 30, 2000 (Inception) through December 31, 2000 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management, our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 4 to the financial statements, the Company adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" on January 1, 2001.

Louisiana Generating LLC

Balance Sheet

At December 31, 2001 and 2000

(In thousands)

Louisiana Generating LLC

Statement of Operations

For the year ended December 31, 2001 and the period from March 30,
2000 (inception) through December 31, 2000

(In thousands)

Louisiana Generating LLC

Statement of Cash Flows

For the year ended December 31, 2001 and the period from March 30,
2000 (inception) through December 31, 2000

(In thousands)

Louisiana Generating LLC

Statement of Member's Equity

For the year ended December 31, 2001 and the period from March 30,
2000 (inception) through December 31, 2000

(In thousands)

Louisiana Generating LLC (Louisiana Generating or the Company) is an indirect wholly owned subsidiary of NRG Energy, Inc. (NRG). NRG South Central owns 100% of Louisiana Generating LLC. 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, each of which own a 50% interest in NRG South Central.

Louisiana Generating was formed for the purpose of acquiring, owning, operating and maintaining the electric generating facilities acquired from Cajun Electric Power Cooperative, Inc. (Cajun Electric).

Pursuant to a competitive bidding process, following the Chapter 11 bankruptcy proceeding of Cajun Electric, Louisiana Generating acquired the non-nuclear electric power generating assets of Cajun Electric.

On March 31, 2000, for approximately $1,055.9 million, the Company acquired 1,708 MW of electric power generation facilities located in New Roads, Louisiana (Cajun facilities). The acquisition was financed through a combination of debt and equity from NRG South Central.

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

In recording transactions and balances resulting from business operations, the Company uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives and uncollectible accounts, among others. As better information becomes available (or actual amounts are determinable), the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

The Company considers cash to include cash and short-term investments with original maturities of three months or less.

Inventory consists of coal, spare parts and fuel oil and is stated at the lower of weighted average cost or market (Note 7).

Property, plant and equipment are stated at cost. Depreciation is computed on a straight-line basis over the following estimated useful lives:

Facilities, machinery and equipment		25 to 40 years
Office furnishings and equipment		3 to 10 years

Deferred financing costs consist of legal and other costs incurred to obtain debt financing. These costs are being amortized over the terms of the related debt.

Revenues from the sale of electricity are recorded based upon the output delivered and capacity provided at rates specified under contract terms or prevailing market rates. Under fixed-price contract, revenues are recognized as products or services are delivered. Revenues and related costs under cost reimbursable contract provisions are recorded as costs are incurred. Anticipated future losses on contracts are charged against income when identified.

The Company has entered into a contract with a marketing affiliate for the sale of energy, capacity and ancillary services produced, which enables the affiliate to engage in forward sales and hedging transactions to manage the Company's electricity price exposure. Net gains or losses on hedges by the marketing affiliate, which are physically settled, are recognized in the same manner as the hedged item. The Company receives the net transaction price on all contracts that are physically settled by its marketing affiliate.

The net income or loss of the Company for income tax purposes, along with any associated tax credits, is included in the tax returns of NRG. Accordingly, no provision has been made for federal or state income taxes in the accompanying financial statements.

At December 31, 2001 and 2000, the accompanying financial statements report a balance of $981.3 million and $999.6 million, respectively for net property, plant and equipment. The tax basis of this property is estimated to be $917.2 million and $983.1 million, respectively. The primary difference is due to accelerated tax depreciation.

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 six months of the date of adoption, and the first annual impairment test must be performed in the year the statement is initially adopted.

Louisiana Generating as required is adopting SFAS No. 142 on January 1, 2002. At December 31, 2001, Louisiana Generating had unamortized intangible assets of $1.7 million. These amounts and all intangible assets and goodwill acquired in the future will be accounted for under the new accounting standard. The new accounting standard occasionally causes reductions in earnings when impairment write-downs of goodwill and/or intangible assets are required. Louisiana Generating does not expect to recognize any asset impairments as a result of adopting SFAS No. 142 in the first quarter of 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. Louisiana Generating has not yet 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. Louisiana Generating does not expect to recognize any asset impairments as a result of adopting SFAS No. 144 in the first quarter of 2002.

On March 31, 2000, the Company completed the acquisition of two fossil fueled generating plants from Cajun Electric Power Cooperative, Inc. for approximately $1,055.9 million. The following information summarizes the pro forma results of operations for the year ended December 31, 2000 as if the acquisition had occurred as of the beginning of the year ended December 31, 2000. The pro forma information presented is for informational purposes only and is not necessarily indicative of future earnings or financial position or of what the earnings and financial position would have been had the acquisition of the Cajun facilities been consummated at the beginning of the respective periods or as of the date for which pro forma financial information is presented.

		(In thousands)
Revenues		$	386,416
Operating costs			263,816

	Operating margin		122,600
Depreciation and amortization			27,392
General and administrative expenses			7,598

	Operating income		87,610
Other expense (income), net			(651	)
Interest expense			73,772

Net income		$	14,489

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. Derivatives that have been designated as hedges of assets, liabilities or firm commitments, are accounted for using the fair value method. Changes in the fair value of these instruments are recognized in earnings as offsets to the changes in the fair value of the related hedged assets, liabilities and firm commitments. Derivatives that have been designated as hedges of forecasted transactions are accounted for using the cash flow method. Changes in the fair value of these instruments are deferred and recorded as a component of other accumulated comprehensive income (OCI) until the hedged transactions occur and are recognized in earnings.

SFAS No. 133 applies to NRG South Central's energy and energy related commodities financial instruments, long-term power sales contracts and long-term gas purchase contracts used to mitigate variability in earnings due to fluctuations in spot market prices, hedge fuel requirements at generation facilities and protect investment in fuel inventories. These activities are conducted by an affiliate of NRG South Central and are allocated to the Company.

Property, plant and equipment consists of the following at December 31, 2001 and 2000:

	2001			2000
	(In thousands)
Land	$	3,733		$	3,733
Facilities, machinery and equipment		1,000,608			1,000,958
Construction in progress		20,815			11,587
Office furnishings and equipment		3,619			3,631
Accumulated depreciation		(47,513	)		(20,302	)

Property, plant and equipment, net	$	981,262		$	999,607

Property, plant and equipment consist primarily of the electric generating facilities acquired from Cajun Electric. The assets are comprised of Units 1 and 2 of Big Cajun I and 100% of Units 1 and 2, 58% of Unit 3 of Big Cajun II and 100% of Big Cajun 1 Peaking; an energy control center and headquarters building; a 17.5 mile gas pipeline system; and certain transmission assets and all other substations.

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 will be made semi-annually on each March 15 and September 15 with $25,500,000 due in 2002 and 2003, $15,000,000 due in 2004, 2005 and 2006. The remaining $667,500,000 is due between March 15, 2007 and September 15, 2024. The proceeds of the bonds were used to finance the Company's acquisition of the Cajun generating facilities on March 31, 2000. Effective March 30, 2000 NRG South Central and the Company entered into a Guarantor loan agreement that provides for substantially the same terms and conditions of the bonds.

NRG South Central's obligations in respect to the bonds are secured by a security interest in NRG Central's and South Central's interests in NRG South Central and NRG South Central's membership interest in the Company; all of the assets related to the Cajun facilities including NRG South Central's rights under all intercompany notes between NRG South Central and the Company but excluding those assets of NRG New Roads specifically held for resale; the revenue account and the debt service reserve account.

The Company issued a guarantee in favor of the bondholders, which unconditionally and irrevocably guarantee the payment of principal, of premium (if any) and interest on the bonds. The guarantee is a guarantee of payment and the bond trustee is entitled to make demands for payment under the guarantee any time that amounts due and payable on the bonds have not been paid.

The Company's obligations with respect to the guarantee and the intercompany loan are secured by a mortgage with respect to Big Cajun I and II and an interest in:

NRG South Central may redeem the bonds in whole or in part at any time at a redemption price equal to:

NRG South Central established a debt service reserve account for the benefit of the bondholders. This account must constitute at all times a sufficient fund to pay the scheduled principal and interest on the bonds due in the next six months. NRG South Central may fund this account with cash or credit support. NRG South Central has obtained credit support and therefore need not fund this account with cash. Currently the debt service reserve requirement is being satisfied by a guarantee given by NRG.

Inventory, which is stated at the lower of weighted average cost or market, at December 31, 2001 and 2000 consists of:

		2001		2000
		(In thousands)
Coal		$	36,571	$	8,099
Spare parts			14,652		15,277
Fuel oil			763		838

	Total	$	51,986	$	24,214

Louisiana Generating entered into a power sale and agency agreement with NRG Power Marketing Inc., a wholly owned subsidiary of NRG. The agreement is effective until December 31, 2030. Under the agreement, NRG Power Marketing Inc. will (i) have the exclusive right to manage, market and sell all power not otherwise sold or committed to or by Louisiana Generating, (ii) procure and provide to Louisiana Generating all fuel required to operate its respective facilities and (iii) market, sell and purchase all emission credits owned, earned or acquired by Louisiana Generating. In addition, NRG Power Marketing Inc. will have the exclusive right and obligation to direct the power output from the facilities.

Under the agreement, NRG Power Marketing, Inc. pays to Louisiana Generating gross receipts generated through sales, less costs incurred by NRG Power Marketing, Inc. relative to its providing services (e.g. transmission and delivery costs, fuel cost, taxes, employee labor, contract services, etc.). The Company incurs no fees related to these power sales and agency agreements with NRG Power Marketing.

Louisiana Generating entered into an operation and maintenance agreement with NRG Operating Services, Inc., (NRG Operating Services) a wholly-owned subsidiary of NRG Energy. The agreement is perpetual in term until terminated in writing by Louisiana Generating or until earlier terminated upon an event of default. Under the agreement, at the request of Louisiana Generating, NRG Operating Services manages, oversees and supplements the operation and maintenance of the Cajun facilities.

The Company incurs no fees related to these power sales and agency agreements with NRG Power Marketing.

Louisiana Generating and NRG South Central each entered into an agreement with NRG Energy for corporate support and services. The agreement is perpetual in term until terminated in writing by Louisiana Generating or NRG South Central or until earlier terminated upon an event of default. Under the agreement, NRG Energy will provide services, as requested, in areas such as human resources, accounting, finance, treasury, tax, office administration, information technology, engineering, construction management, environmental, legal and safety. Under the agreement, NRG Energy is paid for personnel time as well as out-of-pocket costs.

During the year ended December 31, 2001 and the period March 30, 2000 (inception) through December 31, 2000, Louisiana Generating incurred approximately $0.6 million and $0.5 million, respectively, for corporate support and services.

At December 31, 2001 and 2000, the Company had an accounts payable-affiliates balance of approximately $(16.8) and $38.1 million, respectively, which consisted primarily of a payable to NRG Energy for capitalized development costs incurred prior to the acquisition of the Cajun facilities and other expenses paid on Louisiana Generating's behalf.

The Company retained a number of the administrative and operating personnel of Cajun Electric upon acquisition of Cajun Electric's generating facilities. Prior to March 31, 2000, these employees were participants in the National Rural Electric Cooperative Association's Retirement and Security Program, a master multiple-employer defined benefit plan. Effective March 31, 2000, the Cooperative's defined benefit and 401(k) plans were terminated and no on-going pension obligation was assumed by the Company or NRG. The Company sponsors a cash balance pension plan arrangement whereby the employees are entitled to a pension benefit of approximately 7% of total payroll. The employees are also eligible to participate in a 401(k) plan that provides for the matching of specified amounts of employee contributions to the plan.

For the year ended December 31, 2001 and the period March 30, 2000 (inception) through December 31, 2000, the Company recorded approximately $0.26 million and $1 million of pension expense and approximately $458,164 and $265,000, respectively, of 401(k) matching funds.

For the year ended December 31, 2001, sales to two customers accounted for 16.4% and 15.7%, respectively of the Company's total revenues. During the period March 30, 2000 (Inception) through December 31, and 2000, sales to two customers accounted for 16.7% and 16.1%, respectively, of the Company's total revenues. During March 2000, the Company entered into certain power sales agreements with eleven distribution cooperatives that were customers of Cajun Electric prior to the acquisition of the Cajun facilities. The initial terms of these agreements provide for the sale of energy, capacity and ancillary services for the periods ranging from four to 25 years. In addition, the Company assumed Cajun Electric's obligations under four long-term power supply agreements. The terms of these agreements range from 10 to 26 years. These power sales agreements accounted for the 78.4% and 81.4%, respectively, of the Company's total revenues during the year ended December 31, 2001 and for the period March 30, 2000 (Inception) through December 31, 2000 (Note 12).

The estimated fair value of Louisiana Generating's recorded financial instruments at December 31, 2001 and 2000, are as follows:

	2001				2000
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)
Cash	$	3,208	$	3,208	$	3,146	$	3,146
Long-term debt, including current portion		803,500		789,551		788,750		817,922
Decommissioning funds		4,336		4,336		3,863		3,863

For cash, the carrying amount approximates fair value because of the short-term maturity of those instruments. The fair value of long-term debt is estimated based on the quoted market prices for similar issues. Decommissioning fund investments are comprised of various debt securities of the United States of America and are carried at amortized cost, which approximates their fair value.

In the normal course of business, Louisiana Generating may employ a variety of off-balance sheet instruments to manage its exposure to fluctuations in interest rates and energy and energy related commodities prices. Louisiana Generating does not enter into transactions for speculative purposes.

Accordingly, Louisiana Generating classifies its derivative financial instruments as held or issued for purposes other than trading.

From time to time, Louisiana Generating may use interest rate hedging instruments to protect it from an increase in the cost of borrowing. At December 31, 2001 and 2000, there were no such instruments outstanding.

Louisiana Generating is exposed to commodity price variability in electricity, emission allowances, natural gas, oil and coal used to meet fuel requirements. In order to manage these commodity price risks, Louisiana Generating enters into transactions for physical delivery of particular commodities for a specific period. These financial instruments are used to hedge physical deliveries, which may take the form of fixed price, floating price or indexed sales or purchases, and options, such as puts, calls, basis transactions and swaps. These transactions are utilized to:

During March 2000, the Company 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.

Six of the distribution cooperatives entered into Form A power supply agreements. The Form A agreement is an all-requirements power supply agreement which has an initial term of 25 years, commencing on March 31, 2000. After the initial term, the agreement continues on a year-to-year basis, unless terminated by either party giving five years advanced notice.

Under the Form A power supply agreement, the Company is obligated to supply the distribution cooperative all of the energy and capacity required by the distribution cooperative for service to its retail customers although the distribution cooperative has certain limited rights under which it can purchase energy and capacity from third parties.

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

The Company owns and maintains the substations and other facilities used to deliver energy and capacity to the distribution cooperative and charges the cooperative a monthly specific delivery facility charge for such facilities any additions to, or new delivery facilities. The initial monthly charge is 1% of the value of all of the distribution cooperative's specific delivery facilities. The cost of additional

investment during the term of the agreement will be added to the initial value of the delivery facilities to calculate the monthly specific delivery facility charge.

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

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.

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

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

For base supply, the Company charges the distribution cooperative a demand charge, an energy charge and a fuel charge. The demand charge for each contract year is set forth in the agreement and is subject to increase for environmental legislation or occupational safety and health laws enacted after the effective date of the agreement. The Company can increase the demand charge to the extent its cost of providing supplemental supply exceeds $400/MW. The energy charge is fixed through 2004, and decreases slightly for the remainder of the contract term. The fuel charge is a pass-through of fuel and purchased energy costs. The distribution cooperative may elect to be charged based on a guaranteed coal fired heat rate of 10,600 Btu/kWh, and it may also select fixed fuel factors as set forth in the agreement for each year through 2008. The one distribution cooperative which selected this form of agreement elected to utilize the fixed fuel factors. For the years after 2008, the Company will offer additional fixed fuel factors for five-year periods that may be elected. For the years after 2008, the

distribution cooperative may also elect to have its charges computed under the pass-through provisions with or without the guaranteed coal-fired heat rate.

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

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. The agreement can be terminated by the distribution cooperative at any time with 12 months prior notice given after the first anniversary of the acquisition closing date.

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

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

The SWEPCO Operating Reserves and Off-Peak Power Sale Agreement terminates on December 31, 2007. The agreement requires the Company to supply 100 MW of off-peak energy during certain hours of the day to a maximum of 292,000 MWh per year and an additional 100 MW of operating reserve capacity and the associated energy within ten minutes of a phone request during certain hours to a maximum of 43,800 MWh of operating reserve energy per year. The obligation to purchase the 100 MW of off-peak energy is contingent on the Company's ability to deliver operating reserve capacity and energy associated with operating reserve capacity. At the Company's request it will supply up to 100 MW of 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 the Company to provide 50 MW of operating reserve capacity within 10 minutes of a phone request. In addition, SWEPCO is granted the right to purchase up to 21,900 MWh/year of operating reserve energy.

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

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

The Company 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 Powder River Basin, Wyoming. The Coal supply agreement has a term of five years from March 31, 2000. The agreement is for the full coal requirements of Big Cajun II. The agreement establishes a base price per ton for coal supplied by Triton Coal. The base price is subject to adjustment for changes in the level of taxes or other government fees and charges, or variations in the caloric value of the coal shipped or changes in the price of SO(2) emission allowances. The base price is based on certain annual weighted average quality specifications, subject to suspension and rejection limits. The base price and quality of coal specifications guarantee compliance with Big Cajun II's annual SO(2) emissions allocation of 44,153 tons commencing in 2000 regardless of the burn level.

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

The Company assumed Cajun Electric's existing transmission agreements with Central Louisiana Electric Company, SWEPCO; and Entergy Services, Inc., acting as agent for Entergy Arkansas, Inc., Entergy Gulf States, Entergy Louisiana, Inc., Entergy Mississippi, Inc., and Entergy New Orleans, Inc. The Cajun facilities are connected to the transmission system of Entergy Gulf States and power is delivered to the distribution cooperatives at various delivery points on the transmission systems of Entergy Gulf States, Entergy Louisiana, Central Louisiana Electric Company and SWEPCO. The Company also assumed from Cajun Electric 20 interchange and sales agreements with utilities and cooperatives, providing access to a 12 state area.

On March 31, 2000 Louisiana Generating acquired a 58% interest in the Big Cajun II, Unit 3 generation plant. Entergy Gulf States owns the remaining 42%. Big Cajun II, Unit 3 is operated and maintained by Louisiana Generating pursuant to a joint ownership participation and operating agreement. Under this agreement, Louisiana Generating and Entergy Gulf States are each entitled to their ownership percentage of the hourly net electrical output of Big Cajun II, Unit 3. All fixed costs are shared in proportion to the ownership interests. Fixed costs include the cost of operating common facilities. All variable costs are borne in proportion to the energy delivered to the owners. The Company's income statement includes the Company's share of all fixed and variable costs of operating the unit. The Company's 58% share of the original cost included in Plant, Property and Equipment at December 31, 2001 and 2000 was $179.6 and $179.1 million, respectively. The corresponding accumulated depreciation and amortization was $4.3 and $3.4 million, respectively.

The Company is required by the State of Louisiana Department of Environmental Quality to rehabilitate its Big Cajun II ash and wastewater impoundment areas upon removal from service of the Big Cajun II facilities. On July 1, 1989, a guarantor trust fund (the "Solid Waste Disposal Trust Fund") was established to accumulate the estimated funds necessary for such purpose. The Company's predecessor deposited $1.06 million in the Solid Waste Disposal Trust Fund in 1989, and funded $116,000 annually thereafter, based upon an estimated future rehabilitation cost (in 1989 dollars) of approximately $3.5 million and the remaining estimated useful life of the Big Cajun II facilities. Cumulative contributions to the Solid Waste Disposal Trust Fund and earnings on the investments therein are accrued as a decommissioning liability. At December 31, 2001 and 2000, the carrying value of the trust fund investments and the related accrued decommissioning liability was approximately $4.3 million and $3.9 million, respectively. The trust fund investments are comprised of various debt securities of the United States and are carried at amortized cost, which approximates their fair value.

			2001		2000
ASSETS
Current assets:
	Cash		$	3,208	$	3,146
	Accounts receivable			43,353		52,644
	Accounts receivable—affiliates			16,814		—
	Inventory			51,986		24,214
	Prepaid expenses			2,368		1,530

		Total current assets		117,729		81,534
Property, plant and equipment, net of accumulated depreciation of $47,513 and $20,302				981,262		999,607
Deferred financing costs, net of accumulated amortization of $750 and $323				9,969		10,065
Decommissioning fund investments				4,336		3,863
Other assets, not of accumulated amortization of $78 and $34				2,306		2,328

Total assets			$	1,115,602	$	1,097,397

LIABILITIES AND MEMBER'S EQUITY
Liabilities:
	Current liabilities:
		Note payable to member	$	65,500	$	25,250
		Accounts payable		314		2,439
		Accounts payable—affiliates		—		38,082
		Accrued fuel and purchased power expense		26,115		14,171
		Accrued interest		20,453		21,297
		Other current liabilities		11,355		6,460

		Total current liabilities		123,737		107,699
	Note payable to member			738,000		763,500
	Other non-current liabilities			5,600		4,863

		Total liabilities		867,337		876,062
Member's equity				248,265		221,335

		Total liabilities and member's equity	$	1,115,602	$	1,097,397

		2001			2000
Revenues		$	401,935		$	309,010
Operating costs			273,245			205,188

	Operating margin		128,690			103,822
Depreciation and amortization			27,211			20,335
General and administrative expenses			6,601			5,175

	Operating income		94,878			78,312
Other (expense) income, net			(334	)		651
Interest expense			(72,665	)		(55,981	)

Net income		$	21,879		$	22,982

				2001			2000
Cash flow from operating activities:
	Net income			$	21,879		$	22,982
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization			27,211			20,335
		Amortization of deferred financing costs			427			324
		Changes in assets and liabilities:
			Accounts receivable, net		9,291			(52,644	)
			Inventories		(27,772	)		8,872
			Prepaid expenses		(838	)		(1,330	)
			Accounts payable		(2,125	)		2,439
			Accounts payable—affiliates		(54,896	)		(330	)
			Accrued fuel and purchased power expense		11,944			14,171
			Accrued interest		(844	)		21,297
			Other current liabilities		4,895			5,183
			Cash provided by changes in other assets and liabilities		286			1,413

		Net cash (used in) provided by operating activities			(10,542	)		42,712

Cash flows from investing activities:
	Business acquisition, net of liabilities assumed				—			(1,030,353	)
	Proceeds from disposition of property and equipment				—			9,017
	Capital expenditures				(8,866	)		(5,333	)

		Net cash used in investing activities			(8,866	)		(1,026,669	)

Cash flows from financing activities:
	Proceeds from issuance of long-term debt				—			800,000
	Net proceeds/payments on revolver				40,000			—
	Payment of long-term borrowings				(25,250	)		(11,250	)
	Contributions by members				5,051			230,353
	Deferred financing costs				(331	)		—
	Distribution to members				—			(32,000	)

		Net cash provided by financing activities			19,470			987,103

Net increase in cash and cash equivalents					62			3,146
Cash and cash equivalents at beginning of period					3,146			—

Cash and cash equivalents at end of period				$	3,208		$	3,146

Supplemental disclosures of cash flow information
	Interest paid			$	73,035		$	33,510
	Liabilities assumed in acquisitions				—			4,833

		Member Contributions/ Distributions		Accumulated Income		Accumulated Other Comprehesive Income			Total Members' Equity
		(In thousands)
Balances at March 30, 2000 (Inception)		$	—	$	—	$	—		$	—

Net income			—		22,982		—			22,982
Member contributions, net			198,353		—		—			198,353

Balances at December 31, 2000		$	198,353	$	22,982	$	—		$	221,335

Cumulative effect upon adoption of SFAS 133			—		—		500			500
Impact of SFAS 133 for year ended December 31, 2001			—		—		(500	)		(500	)
Net Income			—		21,879		—			21,879

	Total comprehesive income for the year ended December 31, 2001(*)		—		21,879		—			21,879
										—
Member contributions, net			—		5,051		—			5,051

Balances at December 31, 2001			198,353		49,912		—			248,265