LSP BATESVILLE FUNDING CORP - 10-K Annual Report

LSP Energy Limited Partnership and LSP Batesville Funding Corporation meet the conditions set forth

Indicate by check mark whether the registrants (1) have filed all reports required 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 registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark whether the registrant is an accelerated filer as defined by Rule 12b-2 of the Act. Yes o No þ

As of the last business day of the most recently completed second fiscal quarter, no voting or non-voting common equity was held by non-affiliates.

As of the latest practicable date, the 1% general partnership interest in LSP Energy Limited Partnership was held by LSP Energy, Inc. and the 99% limited partnership interest in LSP Energy Limited Partnership was held by LSP Batesville Holding, LLC. As of March 31, 2003, 100 shares of LSP Batesville Funding Corporation’s common stock, par value $.01 per share, were outstanding, and all of such shares were held by LSP Batesville Holding, LLC.

LSP Energy Limited Partnership (the Partnership) is a Delaware limited partnership formed to develop, construct, own and operate a gas-fired electric generating facility with a design capacity of approximately 837 megawatts, located in Batesville, Mississippi (the Power Facility), and is an indirect, wholly owned subsidiary of NRG Energy, Inc. (NRG Energy).

LSP Batesville Funding Corporation (Funding) was established to maintain the activities necessary to facilitate the acquisition of financing by the Partnership from the institutional debt market and to offer debt securities. On May 21, 1999, the Partnership and Funding issued two series of senior secured bonds which are recorded on the books of the Partnership. Funding is wholly owned by LSP Batesville Holding, LLC (Holding), a Delaware limited liability company. Holding is an indirect wholly owned subsidiary of NRG Energy, Inc.

NRG Energy, Inc. (NRG Energy) is an energy company, primarily engaged in the ownership and operation of power generation facilities and the sale of energy, capacity and related products in the United States and internationally. NRG Energy is a wholly owned subsidiary of Xcel Energy Inc. (Xcel Energy), Xcel Energy directly owns six utility subsidiaries that serve electric and natural gas customers in 12 states. Xcel Energy also owns or has interest in a number of non-regulated businesses, the largest of which is NRG Energy.

Due to a number of reasons, including the overall down-turn in the energy industry, NRG Energy’s financial condition has deteriorated significantly. As a direct consequence, in 2002 NRG Energy entered into discussions with its creditors in anticipation of a comprehensive restructuring. NRG Energy is working toward this goal by selective divestiture of non-core assets, consolidation of management, reorganization and redirection of power marketing philosophy and activities and an overall financial restructuring that will improve liquidity and reduce debt. In connection with its restructuring efforts, it is likely that NRG Energy (and certain of its subsidiaries) will file for Chapter 11 bankruptcy protection. For more information about NRG Energy’s restructuring process, refer to the Form 10-K filed by NRG Energy on March 31, 2003.

The Partnership, Funding, NRG Energy, Inc. and Xcel Energy Inc. file periodic reports and other documents with the Securities and Exchange Commission. The public may read and copy the materials filed with the SEC at the SEC’s Public Reference Room at 450 Fifth Street, NW, Washington, DC 20549. The public may also obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, electronic copies of these periodic filings are available through the Commission’s web site at www.sec.gov.

The Power Facility is an approximately 837 megawatt natural gas-fired, combined-cycle electric generating facility located in Batesville, Mississippi. The Power Facility has three generating units, each consisting of a gas-fired Westinghouse 501F combustion turbine, a heat recovery steam generator, a steam turbine and auxiliary equipment. The infrastructure to support the Power Facility includes (1) an electrical substation and transmission line system, (2) a gas lateral pipeline, (3) water intake facilities and water supply and wastewater discharge pipelines and (4) a water pretreatment system.

The Partnership sells power from two of the Power Facility’s combined-cycle units (approximately 558 megawatts) to Dominion Virginia Power Corporation (Dominion), and sells power from the other unit (approximately 279 megawatts) to Aquila Power Corporation (Aquila) under long-term power purchase agreements. Dominion and Aquila supply the natural gas needed for the Power Facility to produce the power

purchased by them. The Power Facility commenced commercial operations under its power purchase agreements with Dominion and Aquila on August 9, and August 8, 2000, respectively. The initial term of the Dominion agreement is 13 years, beginning on June 1, 2000 and provides Dominion with the option to extend the contract an additional 12 years. The initial term of the Aquila agreement is 15 years and 7 months, beginning on June 1, 2000, and provides Aquila with the option to extend the contract an additional 5 years.

The Power Facility is interconnected with the electrical transmission systems of The Tennessee Valley Authority (TVA) and Entergy Mississippi, Inc. (Entergy). The Power Facility is interconnected with the interstate natural gas pipeline systems of ANR Pipeline Company (ANR) and Tennessee Gas Pipeline Company (Tennessee Gas). The water supply for the Power Facility comes from Enid Lake, a United States government-owned lake located approximately 15 miles from the site of the Power Facility. The day to day operation and maintenance of the Power Facility is performed by NRG South Central Operations Inc. (the assignee of Cogentrix Batesville Operations, LLC), an indirect wholly-owned subsidiary of NRG Energy.

The Partnership does not currently have any employees. LS Power Management, LLC, which is now owned by NRG Energy, provides day-to-day administrative and management services for the Partnership.

Funding conducts no business other than activities associated with the financing of the development and construction of the Power Facility and its related infrastructure. Funding does not currently have any employees.

The Partnership and the Power Facility are subject to many federal, state and local laws that are designed to protect human health and the environment and to ensure worker safety. These laws impose numerous requirements on the construction, ownership and operation of the Power Facility and its infrastructure. For example, the Partnership must obtain and comply with permits for air emissions, water withdrawal, wastewater discharges, construction in wetlands and other regulated activities. Each permit contains its own set of requirements. The Partnership also must implement management practices for handling hazardous materials, preventing spills, planning for emergencies, ensuring worker safety and addressing other operational issues. The Partnership could also be held responsible under these laws for the cleanup of pollutant releases at the Power Facility or at off-site locations where the Partnership has sent wastes. The Partnership believes that it has obtained all environmental permits and approvals necessary for the operation of the Power Facility. In addition, although the partnership can not provide assurance that this will always be the case, the Partnership does not currently anticipate that compliance with liability under applicable environmental or safety requirements will have a material effect on its capital expenditures, earnings or competitive position. The Partnership does not expect to incur material capital expenditures to comply with environmental and safety requirements in this fiscal year or the succeeding fiscal year

Various federal and state laws pertaining to power generation and sales also affect the Partnership and the Power Facility. The Federal Power Act regulates the sale of electricity in the wholesale market. The Federal Energy Regulatory Commission (FERC) is an independent agency within The Department of Energy that regulates the transmission and wholesale sale of electricity in interstate commerce under the authority of The Federal Power Act. FERC is also responsible for licensing and inspecting private, municipal and state-owned hydro electric projects. FERC determines whether a public utility qualifies for exempt wholesale generator (EWG) status under The Public Utility Holding Company Act, which was amended by The Energy Policy Act of 1992.

Federal Power Act. The Federal Power Act gives FERC exclusive rate-making jurisdiction over wholesale sales of electricity and transmission of electricity in interstate commerce. FERC regulates the

owners of facilities used for the wholesale sale of electricity and its transmission in interstate commerce as “public utilities” under the Federal Power Act. The Federal Power Act also gives FERC jurisdiction to review certain transactions and numerous other activities of public utilities.

Under the Federal Power Act, an entity that sells electricity in the wholesale market is a public utility, subject to FERC’s jurisdiction. Public utilities are required to obtain FERC’s acceptance of their rate schedules for wholesale sales of electricity. Because the Partnership is selling electricity in the wholesale market, the Partnership is deemed to be a public utility for purposes of the Federal Power Act. FERC has granted the Partnership the authority to sell electricity at market-based rates. In New England, New York, PJM (Pennsylvania, New Jersey, Maryland, Delaware and parts of the Midwest) the Midwest and California, FERC has established Independent System Operators (ISOs) which file market based rate tariffs, subject to FERC Approval. These tariffs/market rules dictate how the wholesale markets are to operate and how entities with market based rates shall be compensated within those markets. The ISOs in these regions also control access to, pricing of and the operation of the transmission grid within their footprint. Outside of ISO controlled regions, the Partnership is allowed to sell at market based rates as determined by willing buyers and sellers. Access to, pricing for and operation of the transmission grid in such regions is controlled by the local transmission owning utility according to their Pro Forma Open Access Transmission Tariff (OATT) filed with and approved by FERC.

Usually, FERC’s orders which grant the Partnership market-based rate authority reserve the right to revoke or revise the Partnership’s market-based rate authority on a prospective basis if FERC subsequently determines that the Partnership possesses excessive market power. If the Partnership lost its market-based rate authority, the Partnership may be required to obtain FERC’s acceptance of a cost-of-service rate schedule and may become subject to the accounting, record-keeping and reporting requirements that are imposed only on utilities with cost-based rate schedules. It should be noted, however, that the Partnership does have the right at any time to petition FERC to grant cost of service based rates pursuant to Section 205 of the Federal Power Act.

Public Utility Holding Company Act. The Public Utility Holding Company Act, known as PUHCA, provides that any entity that owns, controls or has the power to vote 10% or more of the outstanding voting securities of an “electric utility company,” or a holding company for an electric utility company, is subject to regulation under PUHCA.

Registered holding companies under PUHCA are required to limit their utility operations to a single, integrated utility system and divest any other operations that are not functionally related to the operation of the utility system. In addition, a company that is a subsidiary of a holding company registered under PUHCA is subject to financial and organizational regulation, including approval by the SEC of certain financings and transactions. Under the Energy Policy Act of 1992, however, FERC can determine that a company engaged exclusively in the business of owning or operating an eligible facility used for the generation of electric energy for sale at wholesale is an EWG. Accordingly, it is exempt from PUHCA requirements. In the case of facilities previously operated by regulated utilities, FERC can make an exempt wholesale generator determination only after the state utility commission finds that allowing the facility or facilities to be eligible for EWG status will benefit consumers, is in the public interest, and does not violate state law. Each of the Partnership’s operating subsidiaries has been designated by FERC as an EWG or is otherwise exempt from PUHCA because it is a Qualifying Facility under the Public Utility Regulatory Policy Act of 1978.

The Partnership does not expect to engage in any activities that will subject it to regulation under PUHCA. If the Partnership were to lose its EWG status, it would become subject to regulation under PUHCA. It would be difficult for the Partnership to comply with PUHCA absent a substantial restructuring.

The entire independent power industry in the United States is in turmoil. Many of the Partnership’s competitors have announced plans to scale back their growth, sell assets, and restructure their finances. The results of the wholesale restructuring of the independent power industry are impossible to predict, but they may include consolidation within the industry, the sale or liquidation of certain competitors, the re-regulation

of certain markets, and the long-term reduction in new investment into the industry. Under any scenario, however, the Partnership anticipates that it will continue to face competition from numerous companies in the industry, some of which may have more extensive operating experience, larger staffs, and greater financial resources than the Partnership presently possesses.

Many companies in the regulated utility industry, with which the independent power industry is closely linked, are also restructuring or reviewing their strategies. Several of these companies are discontinuing going forward with unregulated investments, seeking to divest of their unregulated subsidiaries or attempting to have their regulated subsidiaries acquire their unregulated subsidiaries. This may lead to an increased competition between the regulated utilities and the unregulated power producers within certain markets. In such instances, the Partnership may compete with regulated utilities in the development of market designs and rulemaking.

FERC, however, is attempting to level the competitive playing field between regulated utilities and unregulated energy suppliers by providing open, non-discriminatory access to electricity markets and the transmission grid. In April 1996, FERC issued Orders 888 and 889 that required all public utilities to file “open access” transmission tariffs that give wholesale generators, as well as other wholesale sellers and buyers of electricity, access to transmission facilities on a non-discriminatory basis. This led to the formation of the ISOs described above. On December 20, 1999, FERC issued Order 2000, encouraging the creation of Regional Transmission Organizations (RTOs). Finally, on July 31, 2002, FERC issued its Notice of Proposed Rulemaking regarding Standard Market Design. All three orders were intended to eliminate market discrimination by incumbent vertically integrated utilities and to provide for open access to the transmission grid.

The full effect of these changes on the Partnership is uncertain at this time. At this time, five ISOs have been approved and are operational; New England (ISO-NE), New York (NYISO), Pennsylvania, NJ, Maryland, DE and parts of the midwest (collectively PJM), Central Midwest (MISO), South Central (SPP) and in California (CA ISO). Two of these ISOs, PJM and MISO, have been found to also qualify as RTOs. Three other entities have also requested that FERC approve their organizations as RTOs; WestConnect (Desert Southwest); RTO West (Pacific Northwest and Rockies) and Setrans (Southeast).

In the Southeast, Entergy and Southern Company continue to support their RTO, Setrans. The future of Setrans is uncertain given the recent loss of Santee Cooper.

Proposals have been introduced in Congress to repeal PURPA and PUHCA, and FERC has publicly indicated support for the PUHCA repeal effort. If the repeal of PURPA or PUHCA occurs, either separately or as part of legislation designed to encourage the broader introduction of wholesale and retail competition, the significant competitive advantages that independent power producers currently enjoy over certain regulated utility companies would be eliminated or sharply curtailed, and the ability of regulated utility companies to compete more directly with independent power companies would be increased. To the extent competitive pressures increase and the pricing and sale of electricity assumes more characteristics of a commodity business, the economics of domestic independent power generation projects may come under increasing pressure. Deregulation may not only continue to fuel the current trend toward consolidation among domestic utilities, but may also encourage the dis-aggregation of vertically-integrated utilities into separate generation, transmission and distribution businesses.

In addition, the independent system operators who oversee most of the wholesale power markets have in the past imposed, and may in the future continue to impose, price caps and other mechanisms to address some of the volatility in these markets. For example, the independent system operator for the New York power pool and the California independent system operator have imposed price caps. These types of price caps and other mechanisms in New York, California, the New England Power Pool and elsewhere may adversely impact the profitability of the Partnership generation facilities that sell energy into the wholesale power markets. Finally, the regulatory and legislative changes that have recently been enacted in a number of states in an effort to promote competition are novel and untested in many respects. These new approaches to the sale of electric power have very short operating histories, and it is not yet clear how they will operate in times of market stress or pressure, given the extreme volatility and lack of meaningful long-term price history in many of these markets and the imposition of price caps by independent system operators.

At this time the Partnership cannot predict how changing industry conditions may affect the future operation of the Power Facility. The Partnership’s long-term contracts to sell electric generating capacity from the Power Facility to Dominion and Aquila help position the Partnership in the competitive marketplace. A termination of these power purchase contracts would subject the power facility to increased merchant market price volatility.

During 2002, two customers, Dominion and Aquila accounted for 54.3% and 42.7%, respectively, of the Partnership’s total revenues. During 2001, Dominion and Aquila accounted for 60.8% and 30.2%, respectively, of the Partnership’s total revenues. During 2000, Dominion and Aquila accounted for 60.1% and 30.2%, respectively, of the Partnership’s total revenues.

Natural Gas is the Partnership’s primary raw material requirement for the generation of electricity. The Partnership’s customers are responsible for supplying the natural gas used by the Partnership for such generation.

The Partnership has no employees and has entered into operation and maintenance agreements with subsidiaries of NRG Operating Services, Inc., a wholly-owned subsidiary of NRG Energy, Inc.

The Partnership’s and Fundings operations are not divided into financial or geographical segments.

The information presented in this annual report 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,” “contemplates,” “believes,” and similar terms. Forward-looking statements are only predictions or expectations and actual results may differ materially from the expectations expressed in any forward-looking statement. While the Partnership and Funding believes that the expectations expressed in such forward-looking statements are reasonable, the Partnership and Funding 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:


	•	The possibility of a bankruptcy filing in the near future by NRG Energy or one or more of its other subsidiaries, the entry of an order for relief by the Minnesota Bankruptcy Court in respect of a pending involuntary Chapter 11 petition in that court with respect to NRG Energy, or the filing of an involuntary bankruptcy petition in another court by a requisite number of creditors of NRG Energy or any subsidiary, as the case may be;

	•	NRG Energy’s ability or the ability of any of its subsidiaries to reach agreements with its lenders, creditors and other stakeholders regarding a comprehensive restructuring of NRG Energy;

	•	Cost and other effects of legal and administrative proceedings, settlements, investigations and claims;

	•	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 of delay in growth recovery in the U.S. as a consequence of the September 11, 2001 terrorist attacks and other factors;


	•	The effect on the U.S. economy as a consequence of an invasion of Iraq and other potential actions relating to the U.S. government’s efforts to suppress terrorism;

	•	Trade, monetary, fiscal, taxation, and environmental policies of governments, agencies and similar organizations in geographic areas where the Partnership or Funding has a 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;

	•	Customer financial conditions, including solvency and the ability to pay invoices when due.

	•	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 Partnership or its subsidiary; or credit ratings;

	•	Inability of the Partnership or Funding to adequately control or hedge against commodity price volatility due to constraints or limitations on available working capital or market credit.

	•	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 prices 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;

	•	Limitations on the Partnership’s or Funding’s ability to control projects in which NRG Energy has less than 100% interest;

	•	Limited operating history at recently acquired or constructed projects provide only a limited basis for management to project the results of future operations;

	•	Risks associated with timely completion of projects under construction, including obtaining competitive commercial agreements, obtaining regulatory and permitting approvals, local opposition, construction delays and other factors beyond the Partnership’s or Funding’s control;

	•	Factors associated with various investments including competition, operating risks, dependence on certain suppliers and customers, and environmental and energy regulations;

	•	Changes in government regulation or the implementation of new government regulations, or the outcome of any litigation which could adversely affect the continued deregulation of the electric industry;

	•	Changes in market design or implementation of rules that affect Partnership’s ability to transmit or sell power in any market.

	•	Other business or investment considerations that may be disclosed from time to time in the Partnership’s Securities and Exchange Commission filings or in other publicly disseminated written documents.

The Partnership and Funding 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 Partnership’s or Funding’s actual results to differ materially from those contemplated in any forward-looking statements included in this Form 10-K should not be construed as exhaustive.

The Partnership holds title to the Power Facility, the electrical substation and transmission lines, the water pretreatment system and related equipment, all of which are located in Batesville, Mississippi. The Partnership has the right to use the gas lateral pipeline, water intake facilities and water supply and wastewater discharge pipelines for the Power Facility pursuant to 30-year lease agreements with the Industrial Development Authority of Panola County, Mississippi. The Partnership owns the approximately 60-acre site of the Power Facility in fee simple. The Partnership granted a security interest in its properties in connection with the financing of the development and construction of the Power Facility and related infrastructure.

There are no pending material legal proceedings to which the Partnership or Funding is a party or to which any of the Partnership’s or Funding’s property is subject.

Item 5 — Market for Registrant’s Common Equity and Related Stockholder Matters

There is no public market for the partnership interests in the Partnership or the capital stock of Funding.

The 1% general partnership interest in the Partnership is owned by LSP Energy, Inc. and the 99% limited partnership interest in the Partnership is owned by LSP Batesville Holding, LLC. All of the capital stock of Funding is owned by LSP Batesville Holding, LLC. All of the capital stock of LSP Energy, Inc. is owned by LSP Batesville Holding, LLC.

The Partnership made no distributions to LSP Batesville Holding, LLC during the years ended December 31, 2002 and 2001. Distributions of $7,247,000 were made to LSP Batesville Holding, LLC during the year ended December 31, 2000. The Partnership’s ability to make distributions to its partners is limited by the terms of its financing agreements, as described in Note 5 in the notes to financial statements of the Partnership contained in Item 15 Financial Statements and Supplementary Data below.

No equity securities of the Partnership or Funding were sold during the fiscal years ended December 31, 2002, 2001 and 2000 that were not registered under the Securities Act.

Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations

Due to the factors discussed below, as well as other matters discussed herein, NRG Energy’s (the parent company of the Partnership and Funding) financial condition has deteriorated significantly in the recent past.

See “Liquidity” below. As a result, NRG Energy does not contemplate that it will have sufficient funds to make required principal and interest payments on its corporate debt, which means that NRG Energy will remain in default of the various corporate level debt obligations discussed more fully herein. In the absence of a consensual plan of reorganization, it is highly likely that NRG Energy will be required to commence a voluntary chapter 11 bankruptcy proceeding to allow it to implement its own plan of reorganization. The commencement of a voluntary chapter 11 bankruptcy proceeding without a consensual plan of reorganization will increase the possibility of a prolonged bankruptcy proceeding.

An unregulated merchant power company in the United States can be characterized in two ways, as a generator or as an energy merchant, with some companies having characteristics of both. In the United States generators are either outgrowths of regulated utilities, developers or are independent aggregators of plants divested by utilities. Generators have grown through acquisitions or the construction of new power plants. Energy merchants have emphasized risk management and trading skills over the ownership of physical assets. Energy deregulation paved the way for development of these companies, with utilities in some regions forced to sell off some of their generating capacity and buy electricity on the wholesale market or through power procurement agreements.

Both generators and energy merchants prospered in the late 1990’s. Starting in 1999, however, a number of factors began to arise which had a negative effect on the business model for merchant power companies. These factors included:

California — When California restructured its electricity industry in the mid-1990’s, it required utilities to sell generation assets and buy electricity on the wholesale spot market, without the stability of long-term contracts. At the time, California had adequate supplies of power, but the State of California was experiencing unusually high electricity demand growth while new capacity additions were not keeping pace. Supply began to lag behind demand, and previously moderate weather gave way to dryer conditions, reducing hydroelectric supply. Shortages and blackouts ensued in 1999 and 2000. Meanwhile, as wholesale electricity prices moved higher, utilities were not allowed to pass higher costs on to consumers under California’s regulatory regime. Unable to bear the financial burden, PG&E sought Chapter 11 protection and California took over the role of procuring electricity for the utilities. Politicians have criticized the electricity generators and the energy merchants, accusing them of improperly manipulating supply, demand and prices. Merchant power companies in California are now embroiled in protracted litigation with California and private parties, which is discouraging new investment.

Economy — The United States economy, already headed towards a recession by mid-2001, suffered a heavy blow on September 11, 2001. This, along with a decrease in economically driven electricity demand, exacerbated the drop in stock valuations of the energy merchants. Other regions of the world economy have suffered problems as well, which has exposed companies with international assets to losses based on severe currency fluctuations.

Weather — On the whole, the summer of 2001, the winter of 2001/2002 and the summer of 2002 were mild in the United States. This together with excessive new construction in many markets has driven down energy prices significantly.

Enron — The bankruptcy of Enron has devastated the merchant power industry. The public and political perception created by Enron put a stigma on the industry, drove investors away and increased scrutiny of the industry. Enron also played a key role in the energy trading markets, providing a widely used electronic trading platform that accounted for an enormous amount of trading volume. No other company has stepped in to fill this role, and as a result the electricity markets have become far less efficient and liquid.

Credit ratings — The credit rating agencies were sharply criticized for not foreseeing Enron’s problems. As a result, the agencies have been quick to scrutinize the rest of the industry, and have tightened their criteria for creditworthiness. The agencies have downgraded most, if not all, of the industry participants. Many of these downgrades were severe — ratings at times were dropped several notches at once, or dropped more than

once in a span of weeks. This has resulted in most of the energy companies, generators and merchants having non-investment grade credit ratings at this time.

Oversupply — As wholesale electricity prices and market liquidity increased in the late 1990’s the industry went on a building boom. Through 2001 capital was readily available for the industry, encouraging companies to build new generation facilities. The years 2000 and 2001 saw record megawatt capacity additions in the United States, and record years were on the horizon for 2002 and 2003. Even with steady economic growth this would have created an oversupply of generation. Limited economic growth and recession have exacerbated the oversupply situation.

Net loss for the year ended December 31, 2002 was $6.5 million, a decrease of $11.4 million compared to net income of $4.9 million for the year ended December 31, 2001. This change was due to the factors described below.

For the year ended December 31, 2002, the Partnership had total revenues of $53.2 million, compared to $52.5 million of revenue for the year ended December 31, 2001. The revenues consisted primarily of capacity sales under long-term sales agreements. Revenues for the year ended December 31, 2002 are primarily comprised of $28.9 million from the Dominion power purchase agreement, and $22.7 million from the Aquila power purchase agreement. Revenues for the year ended December 31, 2001 are primarily comprised of $31.9 million from the Dominion power purchase agreement, and $15.9 million from the Aquila power purchase agreement.

Operating costs were $20.3 million for the year ended December 31, 2002, which is an increase of $11.5 million, or 130.8% over the prior year. Operating costs represented 38.1% and 16.7% of revenues for the years ended December 31, 2002 and 2001, respectively. Operating costs consisted of fuel of $7.8 million, taxes and fees of $2.2 million, labor and related benefits of $1.9 million, maintenance expense of $8.2 million and other miscellaneous operating costs of $0.2 million. Operating expenses increased due to the cost of energy ($7.5 million) incurred to provide replacement power under the contract with Aquila during a forced outage and major repairs on the Combustion Turbines ($2.5 million). The three Combustion Turbines were out of service from two to four weeks in November and December 2002. Steam Turbine Unit 3 was out of service and under repair from Early March 2002 to Early June 2002.

Depreciation costs were $14.4 million for the year ended December 31, 2002, which is an increase of $0.1 million, or 0.7% over the prior year. The depreciation expense was primarily related to the acquisition costs of the power generation facility, which is being depreciated over thirty years.

Interest expense for the year ended December 31, 2002 was $25.0 million, representing a decrease of $0.4 million, or 1.9% below the prior year. Interest expense related to interest paid on the senior secured bonds.

General and administrative expenses were $0.7 million for the year ended December 31, 2002, which is a decrease of $0.1 million. The expenses consisted primarily of legal and accounting fees, and rating agency fees.

Interest income was $0.7 million for the year ended December 31, 2002, which is a decrease of $1.0 million or 58.8% over the prior year. The decrease is due to lower average balances and a decline in interest rates during the year ended December 31, 2002.

Net income for the year ended December 31, 2001 was $4.9 million, an increase of $5.8 million compared to a net loss of 0.9 million for the year ended December 31, 2000. This change was due to the factors described below.

For the year ended December 31, 2001, the Partnership had total revenues of $52.5 million, compared to $20.4 million of revenue for the year ended December 31, 2000. The increase in revenue is due to commercial operations not beginning until August, 2000. The $52.5 million in revenues consisted primarily of capacity sales under long-term sales agreements. Revenues for the year ended December 31, 2001 are primarily comprised of $31.9 million from the Dominion power purchase agreement, and $15.9 million from the Aquila power purchase agreement.

Operating costs were $8.8 million for the year ended December 31, 2001, which is an increase of $2.7 million, or 45.4% over the prior year. Operating costs represented 16.7% of revenues for the year ended December 31, 2001. Operating costs consisted of taxes and fees of $2.4 million, labor and related benefits of $2.2 million, maintenance expense of $1.8 million, insurance of $1.0 million and other miscellaneous operating costs of $1.4 million. Operating costs were lower in 2000 because the plant did not become operational until August 2000.

Depreciation costs were $14.3 million for the year ended December 31, 2001, which is an increase of $8.5 million, or 146.8% over the prior year. The increase is due to the plant not becoming operational until August 2000. The depreciation expense was primarily related to the acquisition costs of the power generation facility, which is being depreciated over thirty years.

Interest expense for the year ended December 31, 2001 was $25.4 million, representing and increase of $14.2 million, or 127.1% over the prior year. The increase in interest expense is due to the discontinuance of interest capitalization. Interest expense was capitalized as a component of construction in progress until July 2000. Approximately $14.3 million of interest expense was capitalized as a component of construction in progress during the year ended December 31, 2000.

General and administrative expenses were $0.8 million for the year ended December 31, 2001, which is an increase of $0.4 million or 105.9% over the prior year. The expenses consisted primarily of legal and accounting fees, and rating agency fees.

Interest income was $1.7 million for the year ended December 31, 2001, which is a decrease of $0.5 million or 22.2% over the prior year. The decrease is due to a decline in interest rates during the year ended December 31, 2001.

The Power Facility has three generating units, each consisting of a gas-fired combustion turbine, a heat recovery steam generator, a steam turbine and auxiliary equipment. In the third and fourth quarters of 2001, two of the Power Facility’s steam turbines experienced rotor failures, causing a forced outage of those units. The Partnership took the remaining unit out of service in March 2002 in order to carry out modifications to that unit’s steam turbine in response to the failures of the other two steam turbines. The third unit was back in service in June 2002. This situation has not created an event of default under the Partnership’s bond indentures and has not lead to an acceleration of the project debt. The Partnership and Funding to date have made all principal and interest payments on the bonds as scheduled.

The Partnership management’s discussion and analysis of its financial condition and results of operations are based upon the Partnership’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 (GAAP) 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, and related disclosures of contingent assets and liabilities. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges. 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 Partnership evaluates its estimates utilizing historic experience, consultation with experts and other methods Partnership considers reasonable in particular circumstances. In any case, actual results may differ significantly from the Partnership’s estimates. Any effects on the Partnership’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.

The Partnership’s significant accounting policies are summarized in Item 15 — Note 2 of the Consolidated Financial Statements. The following table identifies certain of the significant accounting policies listed in Item 15 — Note 2 of the Consolidated Financial Statements. The table also identifies the judgments required and uncertainties involved in the application of each. These policies, along with the underlying assumptions and judgments made by the Partnership’s management in their application, have a significant impact on the Partnership’s consolidated financial statements. The Partnership identifies its most critical accounting policies as those that are the most pervasive and important to the portrayal of the Partnership’s financial position and results of operations, and that require the most difficult, subjective and/or complex judgments by management regarding estimates about matters that are inherently uncertain.

Of all of the accounting policies identified in the above table, the Partnership believes that the following policies and the application thereof to be those having the most direct impact on the Partnership’s financial position and results of operations.

As of December 31, 2002, the Partnership has a carrying value of approximately $306.9 million of net property, plant and equipment, representing approximately 81.9% of total assets. These amounts represent the estimated fair values at the date of acquisition and construction. These estimates may be adjusted based upon completion of certain procedures including third party valuations.

For those assets that were or are being constructed by the Partnership the carrying value reflects the application of the Partnership’s property, plant and equipment policies which incorporate estimates, assumptions and judgments by management relative to the capitalized costs and useful lives of the Partnership’s generating facilities. Interest incurred on funds borrowed to finance projects expected to require more than three months to complete is capitalized. Capitalization of interest is discontinued when the asset under construction is ready for its intended use or when construction is terminated.

The Partnership evaluates property, plant and equipment and intangible assets for impairment whenever indicators of impairment exist. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the assets to the future net cash flows expected to be generated by the asset, through considering project specific assumptions for long-term power pool prices, escalated future project operating costs and expected plant operations. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets by factoring in the probability weighting of different courses of action available to the Partnership. Generally, fair value will be determined using valuation techniques such as the present value of expected

future cash flows. Assets to be disposed of are reported at the lower of the carrying amount or fair value less the cost to sell. Asset impairment evaluations are, by nature, highly subjective.

The Partnership is primarily an electric generation company. Revenues are recorded based on capacity provided and electrical output delivered at the lesser of amounts billable under the power purchase contracts or the average estimated contract rates over the initial term of the power purchase contracts pursuant to their terms and conditions. Transmission service credit revenues are recognized when actual cash is received. The Partnership continually assesses the collectibility of its receivables, and in the event it believes a receivable to be uncollectible, an allowance for doubtful accounts is recorded or, in the event of a contractual dispute, the receivable and corresponding revenue may be considered unlikely of recovery and not recorded in the financial statements until management is satisfied that it will be collected.

As of December 31, 2002, the Partnership and Funding does not have any significant relationships with structured finance or special purpose entities that provide liquidity, financing or incremental market risk or credit risk.

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, Xcel Energy and NRG Energy put into effect a plan to preserve NRG Energy’s investment grade rating and improve its financial condition. This plan included financial support to NRG Energy from Xcel Energy; marketing certain NRG Energy assets for sale; canceling and deferring capital spending; and reducing corporate expenses.

In response to a possible downgrade, during 2002, Xcel Energy contributed $500 million to NRG Energy, and NRG Energy and its subsidiaries sold assets and businesses that provided NRG Energy in excess of $286 million in cash and eliminated approximately $432.0 million in debt. NRG Energy also cancelled or deferred construction of approximately 3,900 MW of new generation projects. On July 26, 2002, Standard & Poor’s (S&P) downgraded NRG Energy’s senior unsecured bonds to below investment grade, and three days later Moody’s also downgraded NRG Energy’s senior unsecured debt rating to below investment grade. Since July 2002, NRG Energy senior unsecured debt, as well as the secured NRG Northeast Generating LLC bonds and the secured NRG South Central Generating LLC bonds and Secured LSP Energy (Batesville) bonds were downgraded multiple times. After NRG Energy failed to make payments due under certain unsecured bond obligations on September 16, 2002, both Moody’s and S&P lowered their ratings on NRG Energy’s and its subsidiaries’ unsecured bonds once again. Currently, NRG Energy’s unsecured bonds carry a rating of between CCC and D at S&P and between Ca and C at Moody’s, depending on the specific debt issue.

As a result of the downgrade of NRG Energy’s credit rating, declining power prices, increasing fuel prices, the overall down-turn in the energy industry, and the overall down-turn in the economy, NRG Energy has experienced severe financial difficulties. These difficulties have caused NRG Energy to, among other things, miss scheduled principal and interest payments due to its corporate lenders and bondholders, prepay for fuel and other related delivery and transportation services and provide performance collateral in certain instances. NRG Energy has also recorded asset impairment charges of approximately $3.1 billion, related to various operating projects as well as for projects that were under construction which NRG Energy has stopped funding.

and limited recourse debt instruments of NRG Energy and have caused the acceleration of multiple debt instruments of NRG Energy, rendering such debt immediately due and payable. For more specific information regarding NRG Energy’s liquidity issues, refer to “Liquidity Issues” in Item 1 of Form 10-K filed by NRG Energy on March 31, 2003.

In addition to the payment defaults described above, prior to the downgrades many corporate guarantees and commitments of NRG Energy and its subsidiaries required that they be supported or replaced with letter 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 received demands to post collateral aggregating approximately $1.1 billion. NRG Energy is presently working with various secured project lender groups with respect to the issue of posting collateral and is working toward establishing a comprehensive plan of restructuring.

In August 2002, NRG Energy retained financial and legal restructuring advisors to assist its management in the preparation of such comprehensive financial and operational restructuring. NRG Energy and its advisors have been meeting regularly to discuss restructuring issues with an ad hoc committee of its bondholders and a steering committee of its bank lenders (the Ad Hoc Creditors Committees). In November 2002, NRG Energy and Xcel Energy presented a comprehensive plan of restructuring to the Ad Hoc Creditors Committees. The restructuring plan has served as a basis for continuing negotiations between the Ad Hoc Creditors Committees, NRG Energy and Xcel Energy related to a consensual plan of reorganization for NRG Energy. If a comprehensive plan of restructuring is ultimately agreed to, it is highly probable that such a plan would be implemented through the commencement of a voluntary Chapter 11 bankruptcy proceeding. For more specific information regarding NRG Energy’s restructuring efforts, refer to “Liquidity Issues” in Item 1 of Form 10-K filed by NRG Energy on March 31, 2003.

On November 22, 2002, five former NRG Energy executives filed an involuntary Chapter 11 petition against NRG Energy in U.S. Bankruptcy Court for the District of Minnesota. Under provisions of federal law, NRG Energy has the full authority to continue to operate its business as if the involuntary petition had not been filed unless and until a court hearing on the validity of the involuntary petition is resolved adversely to NRG Energy. On December 16, 2002, NRG Energy responded to the involuntary petition, contesting the petitioners’ claims and filing a motion to dismiss the case. On February 19, 2003, NRG Energy announced that it had reached a settlement with the petitioners. The U.S. Bankruptcy Court for the District of Minnesota will hear NRG Energy’s motion to approve the settlement and dismiss the involuntary petition. Two of NRG Energy’s creditors have objected to the motion to dismiss. There can be no assurance that the court will dismiss the involuntary petition. The Bankruptcy Court has discretion in the review and approval of the settlement agreement. There is a risk that the Bankruptcy Court may, among other things, reject the settlement agreement or enter an order for relief under Chapter 11.

On March 26, 2003, Xcel Energy announced that its board of directors had approved a tentative settlement agreement with holders of most of NRG Energy’s long-term notes and the steering committee representing NRG’s bank lenders. The settlement is subject to certain conditions, including the approval of at least a majority in dollar amount of the NRG Energy bank lenders and long-term noteholders and definitive documentation. There can be no assurance that such approvals will be obtained. The terms of the settlement call for Xcel Energy to make payments to NRG Energy over the next 13 months totaling up to $752 million for the benefit of NRG Energy’s creditors in consideration for their waiver of any existing and potential claims against Xcel Energy. Under the settlement, Xcel Energy will make the following payments: (i) $350 million at or shortly following the consummation of a restructuring of NRG Energy’s debt. It is expected this payment would be made prior to year-end 2003; (ii) $50 million on January 1, 2004. At Xcel Energy’s option, it may fill this requirement with either cash or Xcel Energy common stock or any combination thereof; and (iii) $352 million in April 2004.

On May 21, 1999, the Partnership and Funding issued two series of senior secured bonds in the following total principal amounts: $150,000,000 7.164% Series A Senior Secured Bonds due 2014 and $176,000,000

8.160% Series B Senior Secured Bonds due 2025. Principal and interest is payable semi-annually on each January 15 and July 15. As of December 31, 2002 there remains $314.3 million of outstanding senior secured bonds. The senior secured bonds currently carry a rating of B at S&P and B1 at Moody’s.

The outstanding bonds and current working capital facility agreements of the Partnership generally restrict its ability to make dividends or distributions or otherwise transfer funds to NRG Energy under certain circumstances such as failure to maintain a required minimum debt service ratio. As of December 31, 2002, the Partnership did not meet the required minimum debt service coverage ratios and is therefore restricted from making distributions to NRG Energy. As of March 31, 2003, the Partnership had cash and cash equivalents (including amounts in restricted trustee accounts) of approximately $38.2 million.

Net cash (used in)/provided by operations for the year ended December 31, 2002 decreased in comparison to 2001. The most significant changes in working capital related to payments made on Accounts Payable-Affiliate and the Net Loss for the year. Net cash (used in)/provided by operation for the year ended December 31, 2001 increased in comparison to 2000. The increase was primarily due to favorable operating results and working capital changes.

Net cash provided by/(used in) investing for the year ended December 31, 2002 increased in comparison to 2001. The increase is due to the draw down of Investments Held By Trustee. Net cash used in investing activities for the year ended December 31, 2001 decreased in comparison to 2000. The decrease was due to a reduction in capital expenditures.

Net cash used in financing for the year ended December 31, 2002 increased in comparison to 2001. The increase is primarily due to two payments made on the senior secured bonds during 2002, only one payment was required in the bonds first year. Net cash used in financing activities for the year ended December 31, 2001 increased in comparison to 2000. The increase was due to a lack of capital contribution from partners during 2001.

Management forecasts capital expenditures, which includes minor refurbishments and environmental compliance, to total approximately $5 million in the year 2003. The Partnership anticipates funding its ongoing capital requirements through operating cash flows and existing cash. NRG Energy’s capital expenditure program is subject to continuing review and modification. The timing and actual amount of expenditures may differ significantly based upon plant operating history, unexpected plant outages, changes in the regulatory environment, the availability of cash and restructuring efforts.

The Partnership has a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to its capital expenditure program. The following is a summarized table of contractual obligations.

In June 2001, FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” 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. The liability is initially capitalized as part of the cost of the related tangible long-lived asset and thus depreciated over the asset’s useful life. Accretion of the liabilities due to the passage of time will be an operating expense. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws and statutes written or oral contracts, including obligations arising under the doctrine of promissory estoppel. The Partnership is required to adopt SFAS No. 143 on January 1, 2003, the Partnership is in the process of evaluating the impact of adopting SFAS No. 143 on its financial condition.

In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections”, that supersedes 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 of prior periods required. The Partnership has no extraordinary gains or losses resulting from extinguishment of debt during the three years ended December 31, 2002, that will require restatement upon adoption of this part of the statement.

In addition, SFAS No. 145 amends SFAS No. 13, “Accounting for Leases”, 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 were effective for transactions occurring after May 15, 2002. Adoption of SFAS No. 145 is not expected to have a material impact on the Partnership.

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 accounting and reporting for costs associated with exit or disposal activities and nullifies 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 No. 146 are effective for exit or disposal activities that are initiated after December 31, 2002.

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

In January 2003, the FASB issued FASB Interpretation No. 46, Consolidation of Variable Interest Entities (FIN No. 46). FIN No. 46 requires an enterprise’s consolidated financial statements to include subsidiaries in which the enterprise has a controlling interest. Historically, that requirement has been applied to subsidiaries in which an enterprise has a majority voting interest, but in many circumstances the enterprise’s consolidated financial statements do not include the consolidation of variable interest entities with which it has similar relationships but no majority voting interest. Under FIN No. 46 the voting interest approach is not effective in identifying controlling financial interest. The new rule requires that for entities to be consolidated that those assets be initially recorded at their carrying amounts at the date the requirements of the new rule first apply. If determining carrying amounts as required is impractical, then the assets are to be measured at fair value the first date the new rule applies. Any difference between the net amount of any previously recognized interest in the newly consolidated entity should be recognized as the cumulative effect of an accounting change. FIN No. 46 becomes effective in the third quarter of 2003. FIN No. 46 is not expected to have a significant impact on the Partnership.

The Partnership primarily has fixed rate long-term debt outstanding as of December 31, 2002. At December 31, 2002 and 2001 the Partnership had approximately $314.3 million and $322.0 million, respectively, of outstanding bonds at an average fixed interest rate of 7.7%. The Partnership is not significantly exposed to the risk of loss associated with movements in market interest rates primarily because its debt obligations bear fixed interest rates.

Commodity price risk relates to price variability in electricity and natural gas used to meet fuel requirements. The Partnership sells its power generation under fixed-price, long-term power sales contracts. Fuel requirements are provided for under these contracts by the customer, therefore, the Partnership is not exposed to any material commodity price variability or risk.

The Partnership is exposed to credit risk in its risk management activities. Credit risk relates to the risk of loss resulting from the non-performance by a counter party of its contractual obligations. Through NRG Energy’s Treasury department, the Partnership actively manages its counter party credit risk. NRG Energy has an established credit policy in place to minimize overall credit risk.

The financial statements and schedules are listed in Part IV, Item 15 of this Form 10-K.

Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

The Partnership and Funding announced their termination of KPMG LLP as principal independent accountants and their engagement of PricewaterhouseCoopers LLP as their new principal independent

accountants as of May 9, 2001. In connection with its audits for the two fiscal years ended December 31, 1999 and December 31, 2000, and through May 9, 2001, there have been no disagreements with KPMG LLP on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreements if not resolved to the satisfaction of KPMG LLP would have caused them to make reference thereto in their report on the financial statements for such years.

The President and Treasurer (the Certifying Officers) have evaluated the Partnership’s and Funding’s disclosure controls and procedures as defined in the rules of the SEC within 90 days of the filing date of this report and have determined that, except to the extent indicated otherwise in this paragraph, disclosure controls and procedures were effective in ensuring that material information required to be disclosed by the Partnership and Funding in the reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. During the fourth quarter of 2002, the Certifying Officers determined that there were certain deficiencies in the internal controls relating to financial reporting at the Partnership and Funding caused by NRG Energy’s (the Partnership’s and Funding’s parent company) pending financial restructuring and business realignment. During the second half of 2002, there were material changes and vacancies in senior NRG Energy, the Partnership and Funding management positions and a diversion of financial and management resources to restructuring efforts. These circumstances detracted from the Partnership’s and Funding’s ability through its internal controls to timely monitor and accurately assess the impact of certain transactions, as would be expected in an effective financial reporting control environment. the Partnership and Funding have dedicated and will continue to dedicate in 2003 resources to make corrections to those control deficiencies. Notwithstanding the foregoing and as indicated in the certification accompanying the signature page to this report, the Certifying Officers have certified that, to the best of their knowledge, the financial statements, and other financial information included in this report on Form 10-K, fairly present in all material respects the financial conditions, results of operations and cash flows of the Partnership and Funding as of, and for the periods presented in this report.

The Partnership’s and Funding’s Certifying Officers are primarily responsible for the accuracy of the financial information that is represented in this report. To meet their responsibility for financial reporting, they have established internal controls and procedures which, subject to the disclosure in the foregoing paragraph, they believe are adequate to provide reasonable assurance that the Partnership’s and Funding’s assets are protected from loss. There were no significant changes in internal controls or in other factors that could significantly affect these controls subsequent to the date of the Certifying Officers evaluation.

The following financial statements of LSP Batesville Funding Corporation and LSP Energy Limited Partnership and related notes thereto, together with the reports thereon of PricewaterhouseCoopers LLP and KPMG LLP, appearing on pages 21 through 61 are included herein:


	All other schedules have been omitted because they are not required, are not applicable or the information is otherwise set forth in the financial statements or notes thereto.

(3) Exhibits: See Exhibit Index submitted as a separate section of this report.

(b) Reports on Form 8-K. The Partnership filed reports on Form 8-K on the following dates over the last fiscal year: November 27, 2002 and October 24, 2002.

In our opinion, the accompanying balance sheets and the related statements of operations, of stockholder’s equity and of cash flows present fairly, in all material respects, the financial position of LSP Batesville Funding Corporation at December 31, 2002 and 2001, and the results of its operations and its cash flows for the two years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with 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.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the financial statements, the Company’s parent, NRG Energy, Inc., is experiencing credit and liquidity constraints and has various credit arrangements that are in default. As a direct consequence, during 2002 NRG Energy, Inc. entered into discussions with its creditors to develop a comprehensive restructuring plan. In connection with these restructuring efforts, it is likely that NRG Energy, Inc. and certain of its subsidiaries will file for Chapter 11 bankruptcy protection. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

We have audited the accompanying statements of operations, changes in stockholder’s deficit and cash flows of LSP Batesville Funding Corporation for the year ended December 31, 2000. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the results of operations and the cash flows of LSP Batesville Funding Corporation for the year ended December 31, 2000, in conformity with accounting principles generally accepted in the United States of America.

LSP Batesville Funding Corporation (“Funding”) was established on August 3, 1998. Funding’s business purpose is limited to maintaining its organization and activities necessary to facilitate the acquisition of financing by LSP Energy Limited Partnership (“the Partnership”) from the institutional debt market and to offering debt securities. On May 21, 1999, the Partnership and Funding issued two series of senior secured bonds (Note 2). Funding is wholly-owned by LSP Batesville Holding, LLC (“Holding”), a Delaware limited liability company, and ultimately a subsidiary of NRG Energy, Inc.

Holding was established on July 29, 1998 for the purpose of owning and managing the limited partnership interests of the Partnership, the common stock of LSP Energy, Inc. (“Energy”), the general partner of the Partnership, and the common stock of Funding.

The Partnership is a Delaware limited partnership formed in February 1996 to develop, finance, construct, own and operate a gas-fired electric generating facility with a design capacity of approximately 837 megawatts located in Batesville, Mississippi (the “Facility”). The Facility commenced commercial operations under the Power Purchase Agreement (“Aquila PPA”) with Aquila Energy Marketing Corporation (“Aquila”) and Utilicorp United, Inc. (“Utilicorp”) on August 8, 2000 and under the Power Purchase Agreement (“Dominion PPA”) with Dominion Virginia Power Corporation (“Dominion”) on August 9, 2000. Prior to achieving commercial operations under the Aquila PPA and the Dominion PPA, the Partnership had been in the development stage and had not generated any operating revenues.

In response to a possible downgrade, during 2002, Xcel Energy contributed $500 million to NRG Energy, and NRG Energy and its subsidiaries sold assets and businesses that provided NRG Energy in excess of $286 million in cash and eliminated approximately $432.0 million in debt. NRG Energy also cancelled or deferred construction of approximately 3,900 MW of new generation projects. On July 26, 2002, Standard & Poors’ (S&P) downgraded NRG Energy’s senior unsecured bonds to below investment grade, and three days later Moody’s also downgraded NRG Energy’s senior unsecured debt rating to below investment grade. Since July 2002, NRG Energy senior unsecured debt, as well as the secured NRG Northeast Generating LLC bonds, the secured NRG South Central Generating LLC bonds and the Secured LSP Energy (Batesville) bonds were downgraded multiple times. After NRG Energy failed to make payments due under certain unsecured bond obligations on September 16, 2002, both Moody’s and S&P lowered their ratings on NRG Energy’s and its subsidiaries’ unsecured bonds once again. Currently, NRG Energy’s unsecured bonds carry a rating of between CCC and D at S&P and between Ca and C at Moody’s, depending on the specific debt issue. Currently, NRG Energy’s unsecured bonds carry a rating of between CCC and D at S&P and between Ca and C at Moody’s, depending on the specific debt issue. The Partnership’s secured bonds currently carry a rating of B at S&P and B1 at Moody’s.

As a result of the downgrade of NRG Energy’s credit rating, declining power prices, increasing fuel prices, the overall down-turn in the energy industry, and the overall down-turn in the economy, NRG Energy has experienced severe financial difficulties. These difficulties have caused NRG Energy to, among other things, miss scheduled principal and interest payments due to its corporate lenders and bondholders, prepay for fuel and other related delivery and transportation services and provide performance collateral in certain instances NRG Energy has also recorded asset impairment charges of approximately $3.1 billion, related to

various operating projects as well as for projects that were under construction which NRG Energy has stopped funding.

NRG Energy and its subsidiaries have failed to timely make several interest and/or principal payments on its indebtedness. These missed payments have resulted in cross-defaults of numerous other non-recourse and limited recourse debt instruments of NRG Energy and have caused the acceleration of multiple debt instruments of NRG Energy, rendering such debt immediately due and payable. For more specific information regarding NRG Energy’s liquidity issues, refer to “Liquidity Issues” in Item 1 of Form 10-K filed by NRG Energy on March 31, 2003.

In August 2002, NRG Energy retained financial and legal restructuring advisors to assist its management in the preparation of a comprehensive financial and operational restructuring. NRG Energy and its advisors have been meeting regularly to discuss restructuring issues with an ad hoc committee of its bondholders and a steering committee of its bank lenders (the “Ad Hoc Creditors Committees”). In November 2002, NRG Energy and Xcel Energy presented a comprehensive plan of restructuring to the Ad Hoc Creditors Committees. The restructuring plan has served as a basis for continuing negotiations between the Ad Hoc Creditors Committees, NRG Energy and Xcel Energy related to a consensual plan of reorganization for NRG Energy. If a comprehensive plan of restructuring is ultimately agreed to, it is highly probable that such a plan would be implemented through the commencement of a voluntary Chapter 11 bankruptcy proceeding.

To aid in the design and implementation of a plan of reorganization, in the fall of 2002, NRG Energy prepared a comprehensive business plan and forecast. Anticipating that NRG Energy’s creditors will own all or substantially all of the NRG Energy’s equity interests after implementing the restructuring plan, any plans and efforts to integrate NRG Energy’s business operations with those of Xcel Energy were terminated. Using commodity, emission and capacity prices provided by an independent energy consulting firm to develop forecasted cash flow information, 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 at the NRG Energy corporate level.

On November 22, 2002, five former NRG Energy executives filed an involuntary Chapter 11 petition against NRG Energy in U.S. Bankruptcy Court for the District of Minnesota. Under provisions of federal law, NRG Energy has the full authority to continue to operate its business as if the involuntary petition had not been filed unless and until a court hearing on the validity of the involuntary petition is resolved adversely to NRG Energy. On December 16, 2002, NRG Energy responded to the involuntary petition, contesting the petitioners’ claims and filing a motion to dismiss the case. On February 19, 2003, NRG Energy announced that it had reached a settlement with the petitioners. The U.S. Bankruptcy Court for the District of Minnesota will hear NRG Energy’s motion to consider the settlement and/or dismiss the involuntary petition. Two of NRG Energy’s creditors have objected to the motion to dismiss. There can be no assurance that the court will dismiss the involuntary petition. The Bankruptcy Court has discretion in the review and approval of the settlement agreement. There is a risk that the Bankruptcy Court may, among other things, reject the settlement agreement or enter an order for relief under Chapter 11.

On March 26, 2003, Xcel Energy announced that its board of directors had approved a tentative settlement agreement with holders of most of NRG Energy’s long-term notes and the steering committee

representing NRG’s bank lenders. The settlement is subject to certain conditions, including the approval of at least a majority in dollar amount of the NRG Energy bank lenders and long-term noteholders and definitive documentation. There can be no assurance that such approvals will be obtained. The terms of the settlement call for Xcel Energy to make payments to NRG Energy over the next 13 months totaling up to $752 million for the benefit of NRG Energy’s creditors in consideration for their waiver of any existing and potential claims against Xcel Energy. Under the settlement, Xcel Energy will make the following payments: (i) $350 million at or shortly following the consummation of a restructuring of NRG Energy’s debt. It is expected this payment would be made prior to year-end 2003; (ii) $50 million on January 1, 2004. At Xcel Energy’s option, it may fill this requirement with either cash or Xcel Energy common stock or any combination thereof; and (iii) $352 million in April 2004.

NRG Energy expects to have cash available for operations through 2003. This forecast does not assume further investment by Xcel Energy or modification of NRG Energy’s current debt obligations. In the event that NRG Energy is unable to work through the issues as described above and is unable to obtain adequate financing on terms acceptable to NRG Energy to continue its operations, NRG Energy may have to file bankruptcy. NRG Energy’s inability to obtain timely waivers and avoid defaults on their credit obligations could lead to additional involuntary bankruptcy proceedings. As a result, there is substantial doubt as to NRG Energy’s and Fundings’ ability to continue as a going concern.

The accompanying financial statements have been prepared assuming Funding will continue as a going concern. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Effective August 28, 1998, the Partnership entered into agreements with a financial institution (the “Bank”), that provided for financing in the amount of $180,000,000 (the “Tranche A Credit Facility”). Borrowings from this financing were used for the development and construction of the Facility. These agreements also contemplated circumstances under which LSP Batesville Funding Corporation (“Funding”) and Holding would enter into agreements whereby they would issue bonds in the amounts of $100,000,000 (the “Tranche B Bond Facility”) and $50,000,000 (the “Tranche C Bond Facility”), respectively, in order to further finance the construction of the facility. The terms and conditions of the Tranche B Bond Facility and Tranche C Bond Facility were set forth in a letter agreement (the “Letter Agreement”) entered into among the Partnership, Holding and Funding (collectively, the “Borrowers”) and the Bank. Bonds under the Tranche B Bond Facility and Tranche C Bond Facility were never issued.

Pursuant to the Letter Agreement, the Borrowers and the Bank, as underwriter, also agreed to pursue a capital markets offering during the last quarter of 1998. However, due to unfavorable capital markets conditions, the capital markets offering was not completed. Alternatively, on December 15, 1998, the Partnership amended and restated the financing agreements entered into on August 28, 1998. The amended and restated agreements provided for financing in the amount of $305,000,000. The new financing consisted of a $305,000,000 three-year loan facility (the “Bank Credit Facility”) entered into among the Partnership and a consortium of banks.

under the Bank Credit Facility; (b) the mechanism for which loan proceeds, operating revenues, equity contributions and other amounts received by the Partnership were disbursed to pay construction costs, operations and maintenance costs, debt service and other amounts due from the Partnership; (c) the conditions which had to be satisfied prior to making distributions from the Partnership; and (d) the covenants and reporting requirements the Partnership was required to be in compliance with during the term of the Common Agreement.

The Common Agreement prohibited the Partnership from making any distributions to its partners while loans made under the Bank Credit Facility were outstanding.

The Common Agreement also required the Partnership to set aside cash reserves for the cost of performing periodic major maintenance on the Facility, including turbine overhauls, and the credit support, if any, that the Partnership is required to provide to Aquila under the Aquila PPA.

Effective August 28, 1998, the Partnership entered into a Letter of Credit and Reimbursement Agreement (the “LOC Agreement”) with the Bank that provides for letter of credit commitments aggregating $16,980,000. The LOC Agreement provides for the Bank to issue three separate letters of credit (“Letter of Credit A”, “Letter of Credit B” and “Letter of Credit C”). The letters of credit will be used to provide security in favor of Dominion to support the Partnership’s obligations under the Dominion PPA. The LOC Agreement requires the Partnership to pay commitment fees quarterly in arrears, at varying rates on each letter of credit commitment until the expiration of each letter of credit commitment. The Partnership is required to reimburse the Bank for any drawings made by Dominion under the letters of credit.

The Bank had issued Letter of Credit A and Letter of Credit B each in the amount of $5,660,000 as security for the Partnership’s potential incremental replacement power obligation under the Dominion PPA until the earlier of June 1, 2000 and the commercial operations date. On July 21, 2000, Dominion issued a draw of approximately $4,650,000 on each of Letter of Credit A and Letter of Credit B. The draws on Letter of Credit A and Letter of Credit B each converted into 5-year loans (“LOC Loans”). Principal amounts under each LOC loan were repayable in 20 equal quarterly installments of approximately $232,487 on each March 31, June 30, September 30, and December 31 commencing on the first such date subsequent to the commercial operations date of the Dominion Units. On September 30, 2000, the Partnership made principal payments under the LOC Loans aggregating approximately $464,974. During 2000, the Partnership paid approximately $307,000 in interest on the LOC Loans, Dominion reimbursed the Partnership approximately $198,000 of such interest on the LOC loans. Interest on the outstanding LOC Loans was based on 1.50% to 1.625% above the selected London Interbank Offered Rate (“LIBOR”) term of one month. On December 13, 2000, Dominion repaid the Partnership’s outstanding LOC loans of $9,300,000 in full.

Letter of Credit C was issued in the amount of $5,660,000 on the commercial operations date of the Dominion Units as security for the Partnership’s future obligations under the Dominion PPA.

On May 21, 1999, the Partnership and Funding issued two series of Senior Secured Bonds (the “Bonds”) in the following total principal amounts: $150,000,000 7.164% Series A Senior Secured Bonds due 2014 and $176,000,000 8.160% Series B Senior Secured Bonds due 2025. Interest is payable semiannually on each January 15 and July 15, commencing January 15, 2000, to the holders of record on the immediately proceeding January 1 and July 1. Interest is computed on the basis of a 360-day year consisting of twelve 30-day months. The interest rate on the Bonds may be increased under the circumstances described below.

A portion of the proceeds from the issuance of the Bonds was used to repay the $136,000,000 of outstanding loans under the Bank Credit Facility. The remaining proceeds from the issuance of the Bonds were used to pay a portion of the costs of completing the Facility.

Effective May 21, 1999, the Common Agreement was amended and restated in connection with the issuance of the Bonds (the “Amended and Restated Common Agreement”). The Amended and Restated

Common Agreement sets forth, among other things: (a) the mechanism by which Bond proceeds, operating revenues, equity contributions and other amounts received by the Partnership are disbursed to pay construction costs, operations and maintenance costs, debt service and other amounts due from the Partnership and (b) the conditions which must be satisfied prior to making distributions from the Partnership.

The Amended and Restated Common Agreement provides that the following conditions must be satisfied before making distributions from the Partnership to its partners: (1) the Partnership must have made all required disbursements to pay operating and maintenance expenses, management fees and expenses and debt service; (2) the Partnership must have set aside sufficient reserves to pay principal and interest payments on the Exchange Bonds and its other senior secured debt; (3) there cannot exist any default or event of default under the Trust Indenture for the Exchange Bonds; (4) the Partnership’s historical and projected debt service coverage ratios must equal or exceed the required levels; (5) the Partnership must have sufficient funds in its accounts to meet its ongoing working capital needs; (6) the Facility must be complete; and (7) the distributions must be made after the last business day of September 2000.

The Amended and Restated Common Agreement requires that the Partnership set aside reserves for: (1) payments of scheduled principal and interest on the Exchange Bonds and other senior secured debt of the Partnership and the Funding Corporation; (2) the cost of performing periodic major maintenance on the Facility, including turbine overhauls; and (3) the credit support, if any, that the Partnership is required to provide to Aquila under the Aquila PPA. As of December 31, 2001 and 2002, the Partnership has funded reserve accounts for scheduled principal and interest on the Exchange Bonds and periodic major maintenance on the Facility in the amounts of $24.4 million, and $24.9 million, respectively. Such reserve accounts are reflected as Investments held by Trustee-restricted on the Partnership’s December 31, 2002 and 2001 balance sheets.

The Partnership and Funding filed a registration statement with the Securities and Exchange Commission (the “SEC”) for a registered offer to exchange the Bonds for two series of debt securities (the “Exchange Bonds”) which are in all material respects substantially identical to the Bonds. The registration statement became effective on March 7, 2000. Upon such registration becoming effective, the Partnership and Funding offered the Exchange Bonds in return for surrender of the Bonds. Interest on each Exchange Bond accrued from January 15, 2000, the last date interest on the surrendered Bonds was paid.

Principal payments are payable on each January 15 and July 15, commencing on July 15, 2001. Scheduled maturities of the Exchange Bonds are as follows:

The Exchange Bonds are secured by substantially all of the personal property and contract rights of the Partnership and Funding. In addition, Holding and Energy have pledged all of their interests in the Partnership, and Holding has pledged all of the common stock of Energy and all of the common stock of Funding.

The Exchange Bonds are senior secured obligations of the Partnership and Funding, rank equivalent in right of payment to all other senior secured obligations of the Partnership and Funding and rank senior in right of payment to all existing and future subordinated debt of the Partnership and Funding.

The Exchange Bonds are redeemable, at the option of the Partnership and Funding, at any time in whole or from time to time in part, on not less than 30 nor more than 60 days’ prior notice to the holders of that series of Exchange Bonds, on any date prior to its maturity at a redemption price equal to 100% of the outstanding principal amount of the Exchange Bonds being redeemed, plus accrued and unpaid interest on the Exchange Bonds being redeemed and a make-whole premium. In no event will the redemption price ever be less than 100% of the principal amount of the Exchange Bonds being redeemed plus accrued and unpaid interest thereon.

The Exchange Bonds are redeemable at the option of the bondholders if funds remain on deposit in the distribution account for at least 12 months in a row, and the Partnership and Funding cause the bondholders to vote on whether the Partnership and Funding should use those funds to redeem the Exchange Bonds, and holders of at least 66 2/3% of the outstanding Bonds vote to require the Partnership and Funding to use those funds to redeem the Exchange Bonds. If the Partnership is required to redeem Bonds with those funds, then the redemption price will be 100% of the principal amount of the Exchange Bonds being redeemed plus accrued and unpaid interest on the Exchange Bonds being redeemed. In addition, if LS Power, LLC, Cogentrix Energy, Inc. and/or any qualified transferee collectively cease to own, directly or indirectly, at least 51% of the capital stock of Energy (unless any or all of them maintain management control of the Partnership), or LS Power, LLC, Cogentrix Energy, Inc. and/or any qualified transferee collectively cease to own, directly or indirectly, at least 10% of the ownership in the Partnership, then the Partnership and Funding must offer to purchase all of the Exchange Bonds at a purchase price equal to 101% of the outstanding principal amount of the Exchange Bonds plus accrued and unpaid interest unless the Partnership and Funding receive a confirmation of the then current ratings of the Bonds or at least 66 2/3% of the holders of the outstanding Bonds approve the change in ownership.

The Trust Indenture for the Exchange Bonds (the “Trust Indenture”) entered into among the Partnership, Funding and The Bank of New York, as Trustee (the “Trustee”) contains covenants including, among others, limitations and restrictions relating to additional debt other than the Exchange Bonds, Partnership distributions, new and existing agreements, disposition of assets, and other activities. The Trust Indenture also describes events of default which include, among others, events involving bankruptcy of the Partnership or Funding, failure to make any payment of interest or principal on the Exchange Bonds and failure to perform or observe in any material respect any covenant or agreement contained in the Trust Indenture.

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of partners’ capital and of cash flows present fairly, in all material respects, the financial position of LSP Energy Limited Partnership and its Subsidiary at December 31, 2002 and 2001, and the results of their operations and their cash flows for the two years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership’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.

The accompanying consolidated financial statements have been prepared assuming that the Partnership will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, the Partnership’s parent, NRG Energy, Inc., is experiencing credit and liquidity constraints and has various credit arrangements that are in default. As a direct consequence, during 2002 NRG Energy, Inc. entered into discussion with its creditors to develop a comprehensive restructuring plan. In connection with its restructuring efforts, it is likely that NRG Energy and certain of its subsidiaries will file for Chapter 11 bankruptcy protection. These conditions raise substantial doubt about the Partnership’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

We have audited the accompanying statements of operations, changes in partners’ capital (deficit) and cash flows of LSP Energy Limited Partnership for the year ended December 31, 2000. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

In our opinion, the financial statements referred to above present fairly, in all material respects, the results of operations and the cash flows of LSP Energy Limited Partnership for the year ended December 31, 2000, in conformity with accounting principles generally accepted in the United States of America.

LSP Energy Limited Partnership (the “Partnership”) is a Delaware limited partnership formed in February 1996 to develop, construct, own and operate a gas-fired electric generating facility with a design capacity of approximately 837 megawatts located in Batesville, Mississippi (the “Facility”). The Facility commenced operations in August 2000. The Partnership owns 100% of NRG Batesville LLC (Batesville), an inactive subsidiary with no operations. The 1% general partner of the Partnership is LSP Energy, Inc. (“Energy”). The 99% limited partner of the Partnership is LSP Batesville Holding, LLC (“Holding”), a Delaware limited liability company established on July 29, 1998. Holding is owned by Granite Power Partners II LP (“Granite”), a Delaware limited partnership formed to develop independent power projects throughout the United States.

On November 3, 2000, the partners of Granite entered into a purchase agreement for the sale of all of (i) the partnership interests in Granite, the indirect owner of the Partnership and LSP Batesville Funding Corporation (“Funding”), and (ii) all of the membership interests in LS Power Management, LLC, the manager of the Facility, to NRG Energy, Inc., and its affiliates (“NRG Energy”). The sale closed on January 29, 2001. The sale did not result in a change of control under the Trust Indenture (“Trust Indenture”) dated as of May 21, 1999 among Funding, the Partnership and The Bank of New York. On February 6, 2001, NRG Energy entered into a purchase agreement for the remaining 51.37% membership interest in Holding. The sale closed on March 30, 2001. As a result of these transactions, the Partnership is an indirect, wholly-owned subsidiary of NRG Energy. The purchase price paid by NRG Energy in these transactions was not pushed down to the Partnership.

In response to a possible downgrade, during 2002, Xcel Energy contributed $500 million to NRG Energy, and NRG Energy and its subsidiaries sold assets and businesses that provided NRG Energy in excess of $286 million in cash and eliminated approximately $432.0 million in debt. NRG Energy also cancelled or deferred construction of approximately 3,900 MW of new generation projects. On July 26, 2002, Standard & Poors’ (S&P) downgraded NRG Energy’s senior unsecured bonds to below investment grade, and three days later Moody’s also downgraded NRG Energy’s senior unsecured debt rating to below investment grade. Since July 2002, NRG Energy senior unsecured debt, as well as the secured NRG Northeast Generating LLC bonds, the secured NRG South Central Generating LLC bonds and the secured LSP Energy (Batesville) bonds were downgraded multiple times. After NRG Energy failed to make payments due under certain unsecured bond obligations on September 16, 2002, both Moody’s and S&P lowered their ratings on NRG Energy’s and its subsidiaries’ unsecured bonds once again. Currently, NRG Energy’s unsecured bonds carry a rating of between CCC and D at S&P and between Ca and C at Moody’s, depending on the specific debt issue. The Partnership’s secured bonds currently carry a rating of B at S&P and B1 at Moody’s.

various operating projects as well as for projects that were under construction which NRG Energy has stopped funding.

On November 22, 2002, five former NRG Energy executives filed an involuntary Chapter 11 petition against NRG Energy in U.S. Bankruptcy Court for the District of Minnesota. Under provisions of federal law, NRG Energy has the full authority to continue to operate its business as if the involuntary petition had not been filed unless and until a court hearing on the validity of the involuntary petition is resolved adversely to NRG Energy. On December 16, 2002, NRG Energy responded to the involuntary petition, contesting the petitioners’ claims and filing a motion to dismiss the case. On February 19, 2003, NRG Energy announced that it had reached a settlement with the petitioners. The U.S. Bankruptcy Court for the District of Minnesota will hear NRG Energy’s motion to consider the settlement and/or dismiss the involuntary petition. Two of NRG Energy’s creditors have objected to the motion to dismiss. There can be no assurance that the court will dismiss the involuntary petition. The Bankruptcy Court has discretion in the review and approval of the settlement agreement. There is a risk that the Bankruptcy Court may, among other things, reject the settlement agreement or enter an order for relief under Chapter 11.

The outstanding bonds and current working capital facility agreements of the Partnership generally restrict its ability to make dividends or distributions or otherwise transfer funds to NRG Energy under certain circumstances such as failure to maintain a required minimum debt service ratio. As of December 31, 2002, the Partnership did not meet the minimum debt service coverage ratios and is therefore restricted from making distributions to NRG Energy.

NRG Energy expects to have cash available for operations through 2003. This forecast does not assume further investment by Xcel Energy or modification of NRG Energy’s current debt obligations. In the event that NRG Energy is unable to work through the issues as described above and is unable to obtain adequate financing on terms acceptable to NRG Energy to continue its operations, NRG Energy may have to file bankruptcy. NRG Energy’s inability to obtain timely waivers and avoid defaults on their credit obligations could lead to additional involuntary bankruptcy proceedings. As a result, there is substantial doubt as to NRG Energy’s and the Partnership’s ability to continue as a going concern.

The accompanying financial statements have been prepared assuming the Partnership will continue as a going concern. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

The financial statements of the Partnership have been prepared in accordance with accounting principles generally accepted in the United States of America. The consolidated financial statements include the accounts of the Partnership and Batesville. All significant intercompany transactions have been eliminated in consolidation.

The principal business of the Partnership is the ownership and operation, of power generation facilities and the sale of energy, capacity and related products.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect reported amounts of assets and liabilities at the date of the financial statements, disclosure of contingent assets and liabilities a 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 Partnership uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives and uncollectible accounts among others. In addition, estimates are used to test long-lived assets for impairment and to determine fair value of impaired assets. As better information becomes available (or actual amounts are determinable), the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

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

As with any power generation facility, operation of the Facility will involve risk, including performance of the Facility below expected levels of output and efficiency, shut-downs due to the breakdown or failure of equipment or processes, violations of permit requirements, operator error, labor disputes, or catastrophic events such as fires, earthquakes, explosions, floods or other similar occurrences affecting a power generation facility or its power purchasers. The occurrence of any of these events could significantly reduce or eliminate revenues generated by the Facility or significantly increase the expenses of the Facility, adversely impacting the Partnership’s ability to make payments of principal and interest on its debt when due.

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

At December 31, 2002 and 2001, Investments Held by Trustee referred to in Note 4, consisted of commercial paper with original maturities primarily of 90 days or less. The Partnership acquired and classified these debt securities as held-to-maturity because of its intent and ability to hold them to maturity. At December 31, 2002 and 2001, the fair value of each of these investment securities approximated its amortized cost.

Held-to-maturity securities are carried at amortized cost, adjusted for amortization of premiums or accretion of discounts. Such amortization and accretion is included in interest income. Interest income is recognized when earned. Realized gains and losses, and declines in value judged to be other-than-temporary, are included in investment securities gains (losses). There were no sales of investment securities during 2002 and 2001. Maturities of investment securities used to pay for property, plant and equipment are reflected as investments drawn for property, plant and equipment on the statement of cash flows.

The Partnership has recorded investments held by Trustee that have been deposited in specific accounts to meet debt service reserve and major maintenance reserve requirements as required under the terms of the Trust Indenture, and these investments are classified as current or non-current assets based upon when the designated debt service and maintenance requirements are payable.

The Trustee holds all of these investments and the use of the proceeds from maturities is restricted under the terms of the Trust Indenture.

Spare parts consist primarily of spare parts for the Facility’s combustion turbines and are carried at the lower of cost or market, cost determined using the first-in, first-out method.

Property, plant and equipment are stated at cost. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance that do not improve or extend the life of the respective asset are charged to expense as incurred. Depreciation is computed using the straight-line method. The assets and related accumulated depreciation amounts are adjusted for asset retirements and disposals with the resulting gain or loss included in operations. The Partnership expenses all repair and maintenance as incurred, including planned major maintenance.

Long-lived assets and intangibles that are held and used are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Such reviews are performed in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” (SFAS NO. 144) in 2002 and SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of” (SFAS No. 121) in prior years. An impairment loss is recognized if the total future estimated undiscounted cash flows expected from an asset is less than its carrying value. An impairment charge is measured by the difference between an asset’s carrying amount and fair value. Fair values are determined by a variety of valuation methods, including appraisals, sales prices of similar assets and present value techniques.

The Partnership amortizes deferred debt issuance and financing costs as interest expense on a basis which approximates the effective interest method over the terms of the related debt.

The carrying amount of cash and cash equivalents, receivables, accounts payables and accrued liabilities approximate fair value because of the short maturity of these instruments. The fair value of long-term debt is estimated based on quoted market prices.

For all periods, net income is equal to comprehensive income as there were no additional items impacting comprehensive income for these years.

Revenues are recorded based on capacity provided and electrical output delivered at the lesser of amounts billable under the power purchase contracts or the average estimated contract rates over the initial term of the power purchase contracts pursuant to their terms and conditions. Transmission service credit revenues are recognized when actual cash is received.

Financial instruments that potentially subject the Partnership to concentrations of credit risk consist primarily of cash and accounts receivable. Cash accounts are generally held in federally insured banks. Accounts receivable are concentrated within entities engaged in the energy industry. These industry concentrations may impact the Partnership’s overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. Receivables are generally not collateralized.

The Partnership is not an income tax paying entity as income taxes are assessed at the partner level. The financial statements of the partnership do not reflect any income tax effects.

In June 2001, FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” 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. The liability is initially capitalized as part of the cost of the related tangible long-lived asset and thus depreciated over the asset’s useful life. Accretion of the liabilities due to the passage of time will be an operating expense. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws and statutes written or oral contracts, including obligations arising under the doctrine of promissory estoppel. The Partnership is required to adopt SFAS No. 143 on January 1, 2003. The Partnership is in the process of evaluating the impact of adopting SFAS No. 143 on its financial condition.

In addition, SFAS No. 145 amends SFAS No. 13, “Accounting for Leases”, asit 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 were effective for transactions occurring after May 15, 2002. Adoption of SFAS No. 145 is not expected to have a material impact on the Partnership.

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 No. 146 are effective for exit or disposal activities that are initiated after December 31, 2002.

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

In January 2003, the FASB issued FASB Interpretation No. 46, Consolidation of Variable Interest Entities (FIN No. 46). FIN No. 46 requires an enterprise’s consolidated financial statements to include subsidiaries in which the enterprise has a controlling interest. Historically, that requirement has been applied to subsidiaries in which an enterprise has a majority voting interest, but in many circumstances the enterprise’s consolidated financial statements do not include the consolidation of variable interest entities with which it has similar relationships but no majority voting interest. Under FIN No. 46 the voting interest approach is not effective in identifying controlling financial interest. Assets of entities consolidated upon adoption of the new standard will be initially recorded at their carrying amounts at the date the requirements of the new rule first apply. If determining carrying amounts as required is impractical, then the assets are to be measured at fair value the first date the new rule applies. Any difference between the net amount of any previously recognized interest in the newly consolidated entity should be recognized as the cumulative effect of an accounting change. FIN No. 46 becomes effective in the third quarter of 2003. Fin No. 46 is not expected to have a significant impact on the Partnership.

Property, plant and equipment are stated at cost. Depreciation is computed on a straight-line basis over the estimated useful life of 30 years.

Certain components within the facility will require replacement or overhaul at various times during the estimated life of the plant. These components are being depreciated using the straight-line method over their estimated useful lives ranging from two to twelve years. The cost of replacements and overhaul of these components is capitalized and depreciated over their estimated useful lives. Routine maintenance and repairs are charged to expense as incurred.

A common agreement (the “Common Agreement”) tied all of the financing agreements together and set forth, among other things: (a) terms and conditions upon which loans and disbursements were to be made under the Bank Credit Facility; (b) the mechanism for which loan proceeds, operating revenues, equity contributions and other amounts received by the Partnership were disbursed to pay construction costs, operations and maintenance costs, debt service and other amounts due from the Partnership; (c) the conditions which had to be satisfied prior to making distributions from the Partnership; and (d) the covenants and reporting requirements the Partnership was required to be in compliance with during the term of the Common Agreement.

The Common Agreement prohibited the Partnership from making any distributions to its partners while loans made under the Bank Credit Facility were outstanding.

subsequent to the commercial operations date of the Dominion Units. On September 30, 2000, the Partnership made principal payments under the LOC Loans aggregating approximately $464,974. During 2000, the Partnership paid approximately $307,000 in interest on the LOC Loans, Dominion reimbursed the Partnership approximately $198,000 of such interest on the LOC loans. Interest on the outstanding LOC Loans was based on 1.50% to 1.625% above the selected London Interbank Offered Rate (“LIBOR”) term of one month. On December 13, 2000, Dominion repaid the Partnership’s outstanding LOC loans of $9,300,000 in full.

Letter of Credit C was issued in the amount of $5,660,000 on the commercial operations date of the Dominion Units as security for the Partnership’s future obligations under the Dominion PPA.

On May 21, 1999, the Partnership and Funding issued two series of Senior Secured Bonds (the “Bonds”) in the following total principal amounts: $150,000,00 7.164% Series A Senior Secured Bonds due 2014 and $176,000,000 8.160% Series B Senior Secured Bonds due 2025. Interest is payable semi-annually on each January 15 and July 15, commencing January 15, 2000, to the holders of record on the immediately proceeding January 1 and July 1. As of December 31, 2002, there remains $314.3 million of outstanding bonds. The Partnership’s secured bonds currently carry a rating of B at S&P and B1 at Moody’s. The interest rate on the Bonds may be increased under the circumstances described below.

Effective May 21, 1999, the Common Agreement was amended and restated in connection with the issuance of the Bonds (the “Amended and Restated Common Agreement”). The Amended and Restated Common Agreement sets forth, among other things: (a) the mechanism by which Bond proceeds, operating revenues, equity contributions and other amounts received by the Partnership are disbursed to pay construction costs, operations and maintenance costs, debt service and other amounts due from the Partnership and (b) the conditions which must be satisfied prior to making distributions from the Partnership.

The Amended and Restated Common Agreement requires that the Partnership set aside reserves for: (1) payments of scheduled principal and interest on the Exchange Bonds and other senior secured debt of the Partnership and the Funding Corporation; (2) the cost of performing periodic major maintenance on the Facility, including turbine overhauls; and (3) the credit support, if any, that the Partnership is required to provide to Aquila under the Aquila PPA. As of December 31, 2001 and 2002, the Partnership has funded reserve accounts for scheduled principal and interest on the Exchange Bonds and periodic major maintenance on the Facility in the amounts of $24.4 million and $24.9 million, respectively. Such reserve accounts are reflected as Investments held by Trustee-restricted on the accompanying December 31, 2002 balance sheet.

offered the Exchange Bonds in return for surrender of the Bonds. Interest on each Exchange Bond accrued from January 15, 2000, the last date interest on the surrendered Bonds was paid.

Principal payments are payable on each January 15 and July 15, commencing on July 15, 2001. Scheduled maturities of the Exchange Bonds are as follows:

The Exchange Bonds are redeemable, at the option of the Partnership and Funding, at any time in whole or from time to time in part, on not less than 30 nor more than 60 days’ prior notice to the holders of that series of Exchange Bonds, on any date prior to its maturity at a redemption price equal to 101% of the outstanding principal amount of the Exchange Bonds being redeemed, plus accrued and unpaid interest on the Exchange Bonds being redeemed and a make-whole premium. In no event will the redemption price ever be less than 100% of the principal amount of the Exchange Bonds being redeemed plus accrued and unpaid interest thereon.

Partnership distributions, new and existing agreements, disposition of assets, and other activities. The Trust Indenture also describes events of default which include, among others, events involving bankruptcy of the Partnership or Funding, failure to make any payment of interest or principal on the Exchange Bonds and failure to perform or observe in any material respect any covenant or agreement contained in the Trust Indenture. The Partnership is currently restricted from making distributions to LSP Batesville Holding, LLC as a result of insufficient Debt Coverage Service Ratio.

On May 18, 1998, the Partnership entered into the Dominion PPA. Under the terms of the Dominion PPA, the Partnership is obligated to sell, and Dominion is obligated to purchase, approximately 558 megawatts of electrical capacity and dispatchable energy generated from two of the three Combined Cycle Units (“Unit” or “Units”) at the Facility at prices set forth in the Dominion PPA. The initial term of the Dominion PPA is thirteen years, beginning on June 1, 2000. Dominion has the option of extending the term of the Dominion PPA for an additional twelve years by providing the Partnership written notice at least two years prior to the expiration of the initial term. The extended term may be terminated at any time by Dominion with 18 months prior notice to the Partnership.

The Dominion PPA specified an energy delivery milestone deadline of June 1, 2000 for the Dominion Unit. On August 9, 2000, the energy delivery milestone for the Dominion Units was achieved. As a result of the delay in achieving the energy delivery milestone, the Partnership was potentially responsible for the cost of incremental replacement power during the period of delay, subject to a maximum of $20 per kilowatt ($5,660,000) of committed capacity from each Dominion Unit. The Partnership issued two letters of credit each in the amount of $5,660,000 as security for this obligation. Dominion claimed that the Partnership was responsible for an aggregate amount of approximately $9,300,000 of incremental replacement power costs for the period June 1, 2000 through July 19, 2000 and had drawn approximately $4,650,000 on each of the two letters of credit. The draws on the letters of credit each converted into 5-year loans. The Partnership disputed the validity of the draws on the two letters of credit, the amount of the incremental replacement power costs and the methodology used by Dominion to calculate the incremental replacement power costs, including the failure by Dominion to acknowledge the force majeure events notice issued by the Partnership to Dominion claiming delays of the energy delivery milestone date of June 1, 2000, under the Dominion PPA as a result of transportation delays in the delivery of one of the Dominion Unit’s steam turbine generator to the Facility. The Partnership claimed a 21-day delay in the energy delivery milestone date for the first Dominion Unit and a 9-day delay in the energy delivery milestone date for the second Dominion Unit. In connection with this dispute, and as a result of the draw on the letters of credit, the Partnership issued a notice of default to Dominion. In response to this notice of default, on August 17, 2000, Dominion repaid the Partnership accrued interest on the letter of credit loans through August 31, 2000 and placed an amount equal to the draws on the two letters of credit into an escrow account pursuant to an escrow agreement dated August 17, 2000 among Dominion, the Partnership and the Chase Manhattan Bank, as escrow agent, (the “Escrow Agreement”) pending final resolution of this dispute.

On December 13, 2000, the Partnership and Dominion entered into a settlement agreement (“Settlement Agreement”) relating to certain matters occurring or failing to occur prior to the date of the Settlement Agreement, including failure to achieve the energy delivery milestone and the force majeure claim as described above. Effective with the Settlement Agreement, the Escrow Agreement was terminated and the outstanding LOC loans of $9,300,000 were repaid in full.

On December 13, 2000, the Partnership and Dominion entered into the Fourth Amendment to the Dominion PPA (the “Fourth Amendment”). The following is a brief description of the significant provisions contained within the Fourth Amendment:


	(a) Additional energy payment — The Dominion PPA specifies a monthly energy payment based on the amount of electricity delivered to Dominion and an energy rate. The energy rate is $1.00 per megawatt-hour escalated by 3% per year. Under the terms of the Fourth Amendment, an additional energy payment ranging from $.30 per megawatt-hour to $1 per megawatt-hour based upon the average number of operating hours per start for the month will be earned by the Partnership. The lower the average operating hours per start the higher the additional energy payment. Both the energy payment and the additional energy payment are escalated by 3% per year.

	(b) Reservation payment adjustment — The reservation payment for each month of the initial term of the Dominion PPA will be reduced by approximately $23,500 for each of the two Dominion Units, for a total monthly reduction of approximately $47,000.

	(c) The Fourth Amendment establishes the Batesville control area as an authorized control center and clarified some of the provisions of the Dominion PPA as they relate to forced outage hours and imbalance charges. Dominion will hold the Partnership harmless from costs associated with Dominion’s control area redesignation and will pay for additional work performed by the Partnership related to the control center. Such costs would include any charges imposed by the Tennessee Valley Authority (“TVA”) or Entergy Mississippi, Inc. (“Entergy”) to bring about the change in control center. Deviation bands were established to limit the Partnership’s responsibility for forced outage hours when the Batesville control area is the designated control area. In exchange, Dominion was provided the ability to elect that the Partnership share responsibility for imbalance charges assessed by TVA or Entergy in lieu of accumulating forced outage hours for mismatches in generation in the event Dominion elects to disestablish the Batesville control area.

	(d) The Partnership agreed to include CMS Trunkline as a valid interstate pipeline under the Dominion PPA.

Under the terms of the Dominion PPA, Dominion provided natural gas for the testing and commissioning of each of its Units. The Partnership was obligated to reimburse Dominion for the delivered cost of such natural gas. The Partnership purchased approximately $7,375,000 of natural gas from Dominion for the testing and commissioning of each of its Units.

The terms of the Dominion PPA, as amended, require Dominion to make payments to the Partnership including a reservation payment, an energy payment, an additional energy payment, a start-up payment, a system upgrade payment and a guaranteed heat rate payment.

The reservation payment is a monthly payment based on the tested capacity of each Dominion Unit adjusted to specific ambient conditions and the applicable reservation charge. The standard capacity reservation charge is $5.00 per megawatt per month, $6.00 per megawatt per month, and $4.50 per megawatt per month for contract years 1-5, 6-13, and 14-25, respectively. The supplemental (or augmented) capacity reservation charge is $3.25 per megawatt per month, $3.50 per megawatt per month, and $3.00 per megawatt per month for contract years 1-5, 6-13, and 14-25, respectively. The reservation payment may be adjusted downward due to low Unit reliability or availability. However, in the event of an extended forced outage the Partnership may elect to pay for or provide Dominion with replacement power and, thereby, avoid a reduction in the reservation payment due to reduced availability. The Partnership invoiced Dominion approximately $28.1 million, $31.9 million and $12.0 million for reservation payments for fiscal years 2002 and 2001 and the period from commercial operation date through December 31, 2000, respectively. Under the terms of the Fourth Amendment, reservation payments for each month of the initial term was reduced by approximately $23,500 for each of the two Dominion Units, for a total monthly reduction of approximately $47,000.

Beginning in 2001 and through the end of the initial term the total reservation payment due from Dominion will be reduced by approximately $47,000 per month.

Due to the unavailability of testing data at the time of commercial operation of the Dominion units, Dominion and the Partnership agreed to fix the standard and supplemental capacities of the Dominion Units under the power purchase agreement at 243 megawatts and 40 megawatts, respectively. The Partnership committed to retest for the standard capacity and supplemental capacity of the Dominion units by September 30, 2000 and November 30, 2000, respectively. However due to the combustion turbine manufacturer’s 80% load limitation, as described below, the retests were not conducted until after the removal of such advisory. The retests for Dominion Unit No. 1 and Dominion Unit No. 2 were completed on January 19, 2001 and December 22, 2000, respectively. As a result of the retests the standard capacity and supplemental capacity of Dominion Unit No. 1 were adjusted to 243 megawatts and 38 megawatts, respectively, and the standard capacity and supplemental capacity of Dominion Unit No. 2 were adjusted to 242 megawatts and 39 megawatts, respectively. The results of the standard and supplemental capacity tests became effective on the first day following the completion of such retests.

The energy payment is a monthly payment based on the amount of electricity delivered to Dominion and an energy rate. The energy rate is $1.00 per megawatt-hour plus an additional energy payment ranging from $.30 to $1.00 per megawatt-hour. Both Energy payment and the additional energy payment are escalated by 3% per year. The Partnership invoiced Dominion approximately $1.0 million, $1.2 million and $0.3 million for energy payments for fiscal year 2002, 2001 and the period from the commercial operations date through December 31, 2000, respectively.

The start-up payment is a monthly payment based on the number of starts for each Dominion Unit in excess of 250 per year and a start-up charge. The start charge is equal to $5,000 per Unit per start in excess of 250 starts per year. There were no start up payments earned during fiscal years 2002, 2001 or the period from the commercial operations date through December 31, 2000.

The system upgrade payment is a monthly payment based on Dominion’s receipt of a credit or discount for transmission service from the TVA and Entergy due to the Partnership’s payment for system upgrades on TVA’s or Entergy’s transmission systems. The system upgrade payment is due only to the extent that Dominion receives such transmission service credit or discount. As of December 31, 2002, 2001 and 2000, Dominion has received no credit or discount from TVA or Entergy for use of the TVA and Entergy transmission system upgrades. TVA and Entergy have been collecting the transmission service fees and have been providing the system upgrade payments directly to the Partnership as described below.

The guaranteed heat rate payment is a monthly payment based on the difference between the actual operating efficiency of the Dominion Units and the operating efficiency that the Partnership has guaranteed. If the actual operating efficiency of the Dominion Units is higher than the operating efficiency that the Partnership has guaranteed, Dominion is required to pay the Partnership the fuel cost savings that resulted from such higher efficiency. If the actual operating efficiency of the Dominion Units is lower than the operating efficiency that the Partnership has guaranteed, the Partnership is required to pay Dominion the fuel cost expense that resulted from such lower efficiency. During fiscal year 2002, 2001 and the period from the date of commercial operations through December 31, 2000, the Partnership was charged approximately $117,000, $101,000 and $62,000, respectively, by Dominion, relating to the guaranteed heat rate.

The Dominion PPA is a tolling arrangement, whereby Dominion is obligated to supply natural gas to each Dominion Unit. Dominion is obligated to arrange, procure, nominate, balance, transport and deliver to the Facility’s lateral pipeline the amount of fuel necessary for each Dominion Unit to generate its net electrical output.

The Dominion PPA requires the Partnership and Dominion to work together to develop an annual schedule for the maintenance based upon Dominion’s projected dispatch schedule. The Partnership has agreed

not to schedule maintenance during the months of June, July, August, September, January and February without Dominion’s consent.

On May 21, 1998, the Partnership entered into the Aquila PPA. Under the terms of the Aquila PPA, the Partnership is obligated to sell, and Aquila is obligated to purchase, approximately 281 megawatts of electrical capacity and dispatchable energy generated from one of the three Units at the Facility at prices set forth in the Aquila PPA. Utilicorp has appointed Aquila as its agent under the Aquila PPA. The initial term of the Aquila PPA is fifteen years and seven months, beginning on June 1, 2000. Aquila has the option of extending the term of the Aquila PPA for an additional five years by providing the Partnership written notice by the later of July 2013 or twenty-nine months prior to the expiration of the initial term.

The Aquila PPA specified an energy delivery milestone deadline of June 1, 2000 for the Aquila Unit. On August 8, 2000, the energy delivery milestone of the Aquila Unit was achieved. During the period of delay, the Partnership had the option of electing to incur an adjustment to the reservation payment to be received under the Aquila PPA or to be responsible for the incremental replacement power costs during the period of delay. The Partnership elected to incur an adjustment to the reservation payments to be received under the Aquila PPA. The adjustment to the future reservation payments was determined by contract capacity, the duration of delay and a percentage factor for the month in which the delay occurred. As a result of the delay in achieving the energy delivery milestone, the reduction in reservation payments received for the period from the commercial operations date through December 31, 2000 approximated $1,335,000. The delay which caused the aforementioned reduction in reservation payments will have no impact on reservation payments earned under the Aquila PPA subsequent to December 31, 2000.

Under the terms of the Aquila PPA, Aquila provided natural gas for the testing and commissioning of its Unit. The Partnership was obligated to reimburse Aquila for the delivered cost of such natural gas. The Partnership purchased approximately $4,602,000 of natural gas from Aquila for the testing and commissioning of its Unit.

Under the terms of the Aquila PPA, Aquila acted as the Partnership’s agent for the purpose of marketing and selling test energy generated during the testing and commissioning of the Aquila Unit. In return for Aquila’s services, the Partnership was obligated to pay Aquila a marketing fee equal to $0.25 per MW hour of test energy sold plus a reimbursement for any reasonable costs related to the sale of such test energy. For the period from May 23, 2000 through the commercial operations date under the Aquila PPA, the Partnership recorded approximately $2,940,000, net of related marketing fees, from the sale of test energy during construction under this arrangement with Aquila.

The terms of the Aquila PPA require Aquila to make payments to the Partnership including a reservation payment, an energy payment, a start-up payment, a system upgrade payment and a guaranteed heat rate payment.

The reservation payment is a monthly payment based on the tested contract capacity of each Aquila Unit adjusted to specific ambient conditions and the applicable reservation charge. The capacity reservation charge for all contract capacity up to 267-megawatts is $4.90 per megawatt per month for the first 60 months and $5.00 per megawatt per month thereafter. The capacity reservation charge for all capacity in excess of 267-megawatts is $2.50 per megawatt per month through the term of the Aquila PPA. The reservation payment may be adjusted downward due to low Unit reliability or availability. However, in the event of an extended forced outage the Partnership may elect to pay for or provide Aquila with replacement power and, thereby, avoid a reduction in the reservation payment due to reduced availability. The Partnership invoiced Aquila approximately $16.0 million, $15.9 million and $6.0 million for reservation payments during fiscal years 2002, 2001 and for the period from commercial operations through December 31, 2000, respectively. The amount for fiscal year 2000 was then reduced by a delay adjustment of approximately $1.3 million.

Due to the unavailability of testing data at the time of commercial operation of the Aquila Unit, Aquila and the Partnership agreed to fix the standard and supplemental capacities of the Aquila Units under the power purchase agreement at 243 megawatts and 38 megawatts, respectively. The Partnership, committed to retest for the standard and supplemental capacity of the Aquila Unit by November 30, 2000. However, due to the combustion turbine manufacturer’s 80% load limitation, as described below, the Partnership was not able to perform the retests on or before November 30, 2000. The retests were completed on February 12, 2001. As a result of the retests the contract capacity and surplus supplemental capacity were adjusted to 267 megawatts and 14 megawatts, respectively. The results of such tests became effective on February 13, 2001.

The energy payment is a monthly payment based on the amount of electricity delivered to Aquila and an energy rate. The energy rate is $1.00 per megawatt-hour escalated by the rate of change in the gross domestic product implicit price deflator index.

The start-up payment is a monthly payment based on the number of starts for the Aquila Unit is excess of 200 per year and a start charge. The start charge is equal to $5,000 per Unit per start.

The system upgrade payment is a monthly payment based on Aquila’s receipt of a credit or discount for transmission service from TVA or Entergy due to the Partnership’s payment for system upgrades on TVA’s or Entergy’s transmission systems. The system upgrade payment is due only to the extent that Aquila receives such transmission service credit or discount. As of the end of December 2000, Aquila had received no credit or discount from TVA or Entergy for use of the TVA and Entergy transmission system upgrades. TVA and Entergy have been collecting the transmission service fees and have been providing the system upgrade payment directly to the Partnership as described below.

The guaranteed heat rate payment is a monthly payment based on the difference between the actual operating efficiency of the Aquila Unit and the operating efficiency that the Partnership has guaranteed. If the actual operating efficiency of the Aquila Unit is higher than the operating efficiency that the Partnership has guaranteed, Aquila is required to pay the Partnership the fuel cost savings that resulted from such higher efficiency. If the actual operating efficiency of the Aquila Units is lower than the operating efficiency that the Partnership has guaranteed, the Partnership is required to pay Aquila the fuel cost expense that resulted from such lower efficiency.

The Aquila PPA is a tolling arrangement, whereby Aquila is obligated to supply natural gas to the Aquila Unit. Aquila is obligated to arrange, procure, nominate, balance, transport and deliver to the Facility’s lateral pipeline the amount of fuel necessary for the Aquila Unit to generate its net electrical output.

The Aquila PPA requires the Partnership and Aquila to work together to develop an annual schedule for the maintenance of the Aquila Unit based upon Aquila’s projected dispatch schedule. The Partnership has agreed not to schedule maintenance during the period from June 15 through September 15 of any calendar year without Aquila’s consent.

The Partnership is entitled to receive transmission system upgrade credits in the amount of incremental revenue received by the TVA and Energy for transmission services procured for the delivery of energy from the Facility.

On July 22, 1998, the Partnership entered into a $241 million fixed price Turnkey Engineering, Procurement and Construction Contract (“Construction Agreement”), including change orders, with BVZ Power Partners/ Batesville (“BVZ”), a joint venture formed by H.B. Zachary Company and a subsidiary of Black & Veatch, LLP. The obligations of BVZ are guaranteed by Black & Veatch, LLP and the entire Construction Agreement is backed by a performance bond. Under the terms of the Construction Agreement, BVZ had committed to develop and construct the Facility subject to the terms, deadlines and conditions set forth in the Construction Agreement. In the event the construction and start-up to specified performance levels of the two Dominion Units and the Aquila Unit had not occurred on or prior to August 2, 2000, July 31,

2000 and July 31, 2000, as adjusted under the terms of the Construction Agreement (“Guaranteed Completion Dates”), respectively, then BVZ would be required under the contract to pay liquidated damages, subject to limits. The Guaranteed Completion Dates included extensions as a result of; (1) the settlement of a force majeure event, and (2) resolutions of issues related to the quality of water provided by the Partnership. In addition, the Partnership reimbursed BVZ approximately $325,000 of the costs associated with the work performed on the water treatment system.

BVZ was required to pay delay liquidated damages of $43,333 per day per Unit for failure to complete the construction and start-up of any Unit to specified minimum performance levels on or prior to one day after the Guaranteed Completion Date. Based on the dates of completion of construction and start-up of the Aquila Unit and the Dominion Units, BVZ paid the Partnership approximately $693,000 of delay liquidated damages. The delay liquidated damages did not fully compensate the Partnership for the delay delivery adjustments under the Aquila PPA or other costs associated with delays.

On September 18, 2000, the Partnership received a technical advisory from the combustion turbine manufacturer on which warned of the potential for hot gas leakage from flanged connections within the turbine enclosure and limited all three combustion turbines to 80% load. In response to this technical advisory, the combustion turbine manufacturer issued a product modification to upgrade the flange connections and to install additional equipment monitors. Work on the product modifications began before the end of November 2000 and all work was completed and the 80% load restriction was removed by January 12, 2001.

During an inspection of the second Dominion Unit’s combustion turbine on May 9, 2000, damage to the compressor blades was discovered. The combustion turbine manufacturer was notified and additional technical support was dispatched to the Facility to determine the cause and extent of the damage and to assist in repairs. During the subsequent investigation and inspection to determine the cause of the damage, impact and/or rubbing damage were identified in each of the 16 stages of the second Dominion Unit’s compressor. All compressor and combustion turbine repairs were completed and the Unit resumed testing on June 12, 2000. Excluding the costs incurred by the Partnership, the cost of the repairs was approximately $1,698,080. Included in such amount is approximately $595,000 of costs recovered by BVZ as a named insured under the Partnership’s insurance policy. These costs were substantially covered through insurance. On March 9, 2001, the Partnership submitted a claim of approximately $1,675,000 to the insurance company. This amount represents the direct costs and delay in opening costs incurred by the Partnership as a result of the compressor damage.

The Partnership entered into electrical interconnection agreements with Tennessee Valley Authority (the “TVA Interconnection Agreement”) and with Entergy Mississippi, Inc. (the “Entergy Interconnection Agreement” and together with the TVA Interconnection Agreement, the “Interconnection Agreements”).

The TVA Interconnection Agreement has a term of thirty-five years, subject to certain amendments for regulatory conformance on a non-discriminatory basis, which amendments could be proposed by the Tennessee Valley Authority at any time after five years from commencement of commercial operations. If the Partnership and TVA fail to reach agreement on such amendment within six months, TVA may terminate the TVA Interconnection Agreement upon giving the Partnership one year’s notice.

The TVA Interconnection Agreement provided for the cost of the interconnection facilities of approximately $4,730,000 and system upgrades of approximately $7,731,000 to be paid by the Partnership. As of December 31, 2000, the interconnection facilities and upgrades have been completed and total costs incurred under the TVA Interconnection Agreement were approximately $12,461,000. The Partnership is entitled to receive system upgrade credits in the amount of incremental revenue received by Tennessee Valley Authority for future transmission services procured for the delivery of energy from the Facility. The amount of such credits may not exceed the total cost of the system upgrades of $7,731,000 paid for by the Partnership.

The Entergy Interconnection Agreement has a term of thirty-five years from the date when the interconnection facilities was completed, automatically extending for subsequent five-year periods.

The Entergy Interconnection Agreement provided for the cost of the interconnection facilities of approximately $966,000 and system upgrades of approximately $6,560,000 to be paid by the Partnership. As of December 31, 2000, the interconnection facilities and system upgrades have been completed and total costs incurred under the Entergy Interconnection Agreement were approximately $7,526,000. The Partnership is entitled to receive system upgrade credits in the amounts of incremental revenue received by Entergy for future transmission services procured for the delivery of energy from the Facility. The amount of such credits may not exceed the total cost of the system upgrades of $6,560,000 paid for by the Partnership. Entergy completed repaying the system upgrade credits in December 2001.

The Partnership entered into an interconnection agreement with ANR Pipeline Company (“ANR”) dated July 29, 1998 to establish an interconnection between the ANR interstate natural gas pipeline system and the Partnership’s lateral natural gas pipeline. Each party was required to design, engineer, and construct its portion of the interconnection, own title to its interconnection and is responsible for insuring those interests.

Under the terms of the interconnection agreement the Partnership was required to reimburse ANR for all reasonable costs, up to $250,000, incurred by ANR with respect to the design, engineering, construction, testing and placing in service of the ANR interconnection facilities. The Partnership may also be required to reimburse ANR for, and hold ANR harmless against, any incremental federal taxes that will be due by ANR if the costs of the ANR interconnection facilities are deemed to be a contribution in aid of construction under the Internal Revenue Code. ANR must use commercially reasonable efforts to minimize such costs.

Each party is generally responsible for the operation, repair and replacement of its portion of the interconnection facilities, and for all associated cost, expense and risk. ANR operates and performs minor maintenance within the capability of ANR’s technicians on the gas measurement equipment, operates, but does not maintain, that portion of the Partnership’s interconnection facilities located on ANR owned land, and, in the case of an emergency involving the Partnership’s interconnection facilities, will take such steps and incur such expense as ANR determines are necessary to abate the emergency and to safeguard life and property. The Partnership will reimburse ANR for all costs and expenses incurred by ANR with respect to such emergencies.

All gas delivered by ANR to the Partnership at the interconnection facilities must conform to specifications set forth in ANR’s tariff and is delivered at ANR’s prevailing line pressure. The Partnership and ANR must each make reasonable efforts to control their respective prevailing line pressure to permit gas to enter the Partnership’s lateral pipeline.

Custody of the gas transfers from ANR to the Partnership’s power purchasers after it passes through the custody transfer point. The custody transfer point is located where the ANR interconnection facilities and the Partnership’s interconnection facilities are connected. The actual quantity of gas delivered by ANR to the Partnership is determined using the recorded meter information at this custody transfer point.

The ANR interconnection agreement is in full force and effect until terminated by the mutual agreement of both parties or the Partnership’s final removal and/or abandonment of the Partnership’s interconnection facilities. Upon notice, either party may terminate the ANR interconnection agreement if the other party materially breaches its obligations.

The Partnership entered into a facilities agreement with Tennessee Gas Pipeline Company (“Tennessee Gas”) dated June 23, 1998 to establish tap facilities and connecting facilities for an interconnection between the Tennessee Gas natural gas pipeline system and the Partnership’s lateral natural gas pipeline. Tennessee Gas was required to design, engineer, install, construct, inspect, test and own the tap facilities. The Partnership was required to design, install, construct and test the connecting facilities. Tennessee Gas has the right of

access to the connecting facilities installed by the Partnership to install tap facilities and to inspect, test and witness the Partnership’s testing of the connecting facilities. Each party was required to ensure its work under the facilities agreement was in accordance with Tennessee Gas’s design specifications, sound and prudent gas industry practice and applicable laws.

Under the terms of the facilities agreement the Partnership was required to reimburse Tennessee Gas for all costs incurred by Tennessee Gas with respect to the design, engineering, installation, construction and testing of the trap facilities and any expenses incurred by Tennessee Gas with respect to the installation of the connecting facilities.

Tennessee Gas is responsible for the operation, repair, replacement and maintenance of the tap facilities, and for all associated cost, expense and risk. The Partnership will provide support for any regulatory authorization or permitting requirements for the tap facilities. Tennessee Gas has the right to inspect the connecting facilities at all reasonable times to ensure that the facilities are installed, operated and maintained correctly.

The Tennessee Gas interconnection agreement is in full force and effect until the final removal and/or abandonment of the tap facilities and connecting facilities, unless terminated by the partnership or by Tennessee Gas as a result of the Partnership’s failure to make timely payments, if gas has not flowed through the connecting facilities for the previous period of 12 consecutive months or in the event the Partnership has caused the connecting facilities to be disconnected or removed. Tennessee Gas cannot cause the final removal and/or abandonment of the tap facilities and connecting facilities without approval of the Federal Energy Regulatory Commission.

The Partnership entered into three contracts aggregating approximately $9,164,000, including change orders for the design and construction of an electrical substation and transmission line system (the “Partnership’s Interconnection Facilities”). The Partnership’s Interconnection Facilities are designed to enable the Partnership to deliver the output of the Facility to the Tennessee Valley Authority and Entergy Mississippi, Inc. interconnection facilities.

The Partnership entered into three contracts aggregating approximately $18,686,000, including change orders for the construction of the Facility’s gas lateral pipeline and the pipelines through which the Facility receives water and disposes of waste water (collectively the “Infrastructure”). Pursuant to change orders effective November 1, 1999, the Partnership transferred these contracts to Panola County, Mississippi (“Panola County”). As described more fully below, the Partnership has leased the Infrastructure under terms which provide the Partnership with the operational control and responsibility for the Infrastructure, and with the use of the Infrastructure for the full projected requirements of the Facility.

The Partnership entered into agreements with State of Mississippi governmental entities. Under an “Inducement Agreement,” (i) the State of Mississippi agreed to issue general obligations bonds (the “Municipal Bonds”) to finance the Infrastructure, (ii) Panola Country (and ultimately the Industrial Development Authority of Panola County (“IDA”)) agreed to assume ownership of the Infrastructure, and (iii) the Partnership agreed to operate and maintain both the Facility and the Infrastructure. As contemplated by the inducement Agreement, the Partnership has transferred to Panola County the construction contracts relating to the Infrastructure and its title to the Infrastructure together with permanent easements and real estate rights relating to the Infrastructure sites. The Partnership paid the cost of constructing the Infrastructure until the State of Mississippi issued the Municipal Bonds to finance the Infrastructure and these transfers had been made. The State of Mississippi has reimbursed the Partnership for the costs that it incurred for development and easement acquisition activities and for the construction of the Infrastructure after April 11, 1999 and has paid substantially all remaining costs due under the Infrastructure contracts. The maximum aggregate amount of costs paid by the State of Mississippi under the Infrastructure contracts could not exceed

$17,000,000. As of December 31, 2000, the State of Mississippi had expended approximately $16,159,000 of such funds. The Partnership received approximately $14,278,000 in 1999 of these funds as a reimbursement.

Under the Inducement Agreement, the Partnership must maintain the Facility and keep the Facility capable of being operated other than during periods when the Facility is not available because of maintenance or repair or for reasons beyond the Partnership’s control, and to perform the Partnership’s obligations under the other Infrastructure agreements. In the event the Partnership fails to do so, the Partnership would be responsible for paying to the State an amount equal to (1) the outstanding principal amount of the Municipal Bonds times a fraction the numerator of which is the number of months remaining in the term of these bonds and the denominator of which is the original number of months in the term of these bonds plus (2) accrued interest on that principal amount plus (3) the costs of redeeming these bonds.

The Partnership entered into agreements with the County and the IDA that allows the Partnership to use the Infrastructure. The Partnership entered into one agreement with respect to the natural gas lateral pipeline and one with respect to the water supply and wastewater discharge systems. Each of these agreements is in the form of a lease each with an initial term of 30 years. In return for the Partnership’s use of the Infrastructure, the Partnership must operate and maintain, or arrange for the operation and maintenance of, the Infrastructure and to pay for all operation and maintenance expenses. The operation and maintenance of the natural gas lateral pipeline is currently performed by Reliant Energy Pipeline Services, Inc. (“Reliant”) and the operation of the water supply and wastewater discharge systems is performed by LSP energy. The Partnership pays Reliant a monthly fee of approximately $5,625 to maintain the natural gas lateral pipeline. Maintenance of the water supply and wastewater discharge systems is outsourced to a third party. The Partnership pays Aquila Energy Marketing Corporation a monthly fee of approximately $10,000 to manage the natural gas that flows through the natural gas lateral pipeline. The Partnership currently expects that the City of Batesville, Mississippi will be an additional user of the capacity of the natural gas lateral pipeline which is in excess of the capacity required to operate the Facility. The Partnership currently expects that there may be additional users in the future of the water supply and wastewater discharge systems. In the case of any such additional user of the water infrastructure, the Partnership has approval rights over the terms and conditions (including cost sharing, indemnification and any restrictions resulting from regulatory limitations) pursuant to which such additional users will be provided access to use the water infrastructure.

In consideration for the approval to locate a portion of the Infrastructure in Yalobusha County, Mississippi and the Coffeeville School District, the Partnership entered into an agreement with Yalobusha County, Mississippi, and the Coffeeville School District to pay them an aggregate amount equal to $1,500,000. This payment is due on or before the first day of February following the first full calendar year after the year in which the Facility was certified substantially complete which occurred on December 5, 2000. This payment constituted a credit against future amounts, if any, of any ad valorem real and/or personal property taxes assessable against and leviable on or with respect to the assessable interest of the Partnership in the water intake Infrastructure. This payment was made in January 2002.

Finally, in consideration for its use of the Infrastructure, the Partnership pays Panola Partnership, Inc. (a County governmental entity) a yearly payment equal to $300,000, which escalates annually, so long as the Inducement Agreement and the use agreements described above remain in effect and are not terminated, other than as a result of a default by the Partnership.

The Partnership entered into a water supply storage agreement with the United States of America (“the Government”), represented by the District Engineer of the Vicksburg District of the United States Army Corps of Engineers (the “District Engineer”), that provides for storage in Enid Lake of the Partnership’s industrial water supply. Enid Lake is approximately 15 miles south of the site of the Facility. The United States Army Corps of Engineers pursuant to the Flood Control Act of March 28, 1928, as amended, constructed and now operates the lake to control flooding in the region.

The Water Supply Storage Agreement continues for the life of the Government’s Enid Lake project. In the event the Government no longer operates Enid Lake, the Partnership’s rights associated with storage may continue subject to the execution of a separate agreement or additional supplemental agreement with the new operator.

The Partnership has an undivided 7.8% of the storage space in Enid Lake that is estimated to contain 4,500 acre-feet after adjustments for sediment deposits. The Partnership may withdraw water from Enid Lake to the extent that its storage space allows.

The Partnership must pay to the Government an amount equal to the cost allocated to the water storage rights acquired by the Partnership, which is 7.8% of the water storage rights at Enid Lake. The Partnership’s cost is estimated to be $1,100,000, subject to adjustments of the year the initial payment is made. This cost is payable over the life of the Enid Lake flood control project, but not to exceed 30 years from the due date of the first annual payment. The first payment was required to be made on the earlier of 30 days after the Partnership’s initial use of the storage or within 24 months after the Partnership’s notification by the District Engineer that this water supply storage agreement is effective.

The unpaid balance of the Partnership’s storage cost will accrue interest at a rate determined pursuant to Section 932 of the 1986 Water Resources Development Act. In 1998, the rate was 6.75%. At this interest rate the Partnership’s combined yearly principal and interest payments would total approximately $81,800, with the first payment to be applied solely against the principal Subsequent to the first payment in 2000, the interest rate will be adjusted at five-year intervals.

In addition to the annual water storage cost, the Partnership must pay, annually, 0.682% of (i) the costs of any repair, rehabilitation or replacement of Enid Lake features as a result of any joint use with another entity utilizing Enid Lake and (ii) the annual joint use operation and maintenance expenses.

The Partnership entered into an Ad Valorem Tax Contract dated as of August 28, 1998 with the County of Panola, Mississippi, the City of Batesville, Mississippi, the Mississippi Department of Economic and Community Development acting for and on behalf of the State of Mississippi and the Panola County Tax Assessor/ Collector (the “Government Entities”). The Government Entities granted to the Partnership several tax reductions and incentives to construct the Facility in Batesville. The Government Entities have agreed that the Partnership is eligible for a fee-in-lieu-of-taxes of not less than one-third of the Partnership’s state and local taxes.

The fee-in-lieu-of-taxes amount which the Partnership must pay equals one-third of the taxes assessed against the Partnership, the Facility, inventories and any assessable interest of the industrial water supply system, the wastewater disposal system, the fire protection system and the lateral gas pipeline, provided that the fee-in-lieu-of-taxes amount will never be less than $1,900,000 per year. The fee-in-lieu-of-taxes is also subject to all mileage changes.

The fee-in-lieu-of-taxes is for a 10-year period beginning on the first January 1st after the Facility was substantially completed, which occurred on December 5, 2000. To the extent lawfully available, the Government Entities will apply this agreement to any expansions, improvements or equipment replacements provided that the Partnership complies with its material obligations under this ad valorem tax agreement.

The Partnership must maintain the Facility and keep it capable of being operated other than during periods when the Facility is not available because of maintenance or repair or for reasons beyond the Partnership’s control. If the Partnership fails to do so, this agreement will terminate on the January 1st following the Partnership’s failure.

Through a letter agreement dated July 20, 1998, the Partnership committed to purchase, and Westinghouse Power Generation agreed to sell, combustion turbine parts for the Facility. The price for the initial order

of parts was approximately $2,096,000. The Partnership receives a 20% discount from the original agreement price adjusted for inflation for any subsequent orders.

These and other contracts and activities incident to operation of the Facility require various other commitments and obligations by the Partnership. Additionally, the contracts contain various restrictive covenants, which allow the contracted party to terminate the contract upon the occurrence of specified events or, in certain cases, default under other contractual commitments.

On January 1, 2001, the Partnership 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 Partnership to record all derivatives on the balance sheet at fair value. Changes in the fair value of non-hedge derivatives will be immediately recognized in earnings. Derivatives that have been designated as hedges of assets, liabilities or firm commitments, will be accounted for using the fair value method. Changes in the fair value of these instruments will be 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 will be accounted for using the cash flow method. Changes in the fair value of these instruments will be deferred and recorded as a component of other accumulated comprehensive income (OCI) until the hedged transactions occur and are recognized in earnings.

During the years ended December 31, 2002 and 2001 the Partnership had no derivative instruments as defined by SFAS No. 133.

The carrying amounts of the Partnership’s cash, investments held by Trustee, accounts payable and contract retainage payable approximate their fair value because of the short maturities of these instruments. The estimated fair value of the Partnership’s bonds payable at December 31, 2002 and 2001 was approximately $224 million and $293 million, respectively. The estimated fair value of the Partnership’s bonds payable was determined based on quoted market prices as of December 31, 2002 and 2001 for similar instruments.

The amended and restated partnership agreement of the Partnership provides that profits and losses are generally allocated between the Partnership’s partners, Energy and Holding, in proportion to the partners’ respective partnership interests. Regular distributions made by the Partnership with available funds are first used to repay loans made by the partners to the Partnership and are then paid to the partners in proportion to their respective partnership interests. Any amounts available for distribution which are comprised of (1) the excess of (x) the net proceeds of the Bonds and committed equity contributions to the Partnership over (y) the aggregate of the project costs for the Facility, or (2) funds released from the debt service reserve account to the Partnership upon the posting of a letter of credit for that account, will be distributed to or as directed by Holding. The Amended and Restated Common Agreement includes conditions that the Partnership must satisfy before making distributions to its partners. In December 2000, the Partnership made a distribution totaling $7,247,000 to Holding in accordance with the terms of the Amended and Restated Common Agreement. No distributions were made in 2002 or 2001.

The Company has no employees and has entered into operation and maintenance agreements with subsidiaries of NRG Operating Services, Inc., a wholly-owned subsidiary of NRG (NRG Operating Services). The agreements were assigned by Cogentrix and are effective for twenty-seven years. Under the agreements, the NRG Operating Services company operator operates and maintains its respective facility, including (i) coordinating fuel delivery, (ii) managing facility spare parts, (iii) meeting external performance standards for transmission of electricity, (iv) providing operating and maintenance consulting and (v) cooperating with and assisting the Partnership in performing the Company’s obligations under agreements related to its facilities.

The Partnership has the option of extending the term of the agreement for successive two-year terms with one hundred and eighty days notice. Under the terms of the agreement the Partnership is required to pay the Operator a fixed monthly fee of approximately $42,000 during operation of the Facility. The Partnership is also required to reimburse the Operator for all labor costs, including payroll and taxes, and other costs deemed reimbursable by the Partnership. The operations and maintenance fee will be adjusted annually based on published indices.

During 2002, 2001 and 2000, the Partnership incurred annual operating costs related to the above agreement totaling $394,800, $129,900 and $435,500, respectively. As of December 31, 2002 and 2001, the Partnership had outstanding amounts payable to NRG Operating Services of $43,900 and $0, respectively.

As of December 31, 2002 and 2001, the balances of accounts payable to affiliate primarily related to labor and operating costs pending payment by the Partnership.

The Partnership is a party to certain claims arising in the ordinary course of business. The Partnership is of the opinion that final disposition of these claims will not have a material adverse effect on the Partnership’s financial position, results of operations or cash flows.

The Partnership is highly dependent on the Operator for the operation and maintenance of the Facility and during the terms of the Dominion PPA and Aquila PPA, the Partnership will be highly dependent on two utilities for the purchase of electric generating capacity and dispatchable energy from their respective units at the Facility. Any material breach by any one of these parties of their respective obligations to the Partnership could affect the ability of the Partnership to make payments under the various financing agreements. In addition, bankruptcy or insolvency of other parties or default by such parties relative to their contractual or regulatory obligations could adversely affect the ability of the Partnership to make payments under the various financing agreements. If an agreement were to be terminated due to a breach of such agreement, the Partnership’s ability to enter into a substitute agreement having substantially equivalent terms and conditions, or with an equally creditworthy third party, is uncertain and there can be no assurance that the Partnership will be able to make payments under the various financing agreements.

During 2002, two customers, Dominion and Aquila accounted for 54.3% and 42.7%, respectively of the Partnership’s total revenues. During 2001, Dominion and Aquila accounted for 60.8% and 30.2%, respectively, of the Partnership’s total revenues. During 2000, Dominion and Aquila accounted for 60.1% and 30.2%, respectively, of the Partnership’s total revenues.

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.


	LSP ENERGY LIMITED PARTNERSHIP
	(Registrant)

	/s/ LSP ENERGY, INC.,
	its general partner

	/s/ RICHARD C. KELLY

	Richard C. Kelly
	President and Director

Each person whose signature appears below constitutes and appoints Richard C. Kelly and George Schaefer, each or any of them, such person’s true and lawful attorney-in-fact and agent with full power of substitution and resubstitution for such person and in such person’s name, place and stead, in any and all capacities, to sign any and all amendments to this report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing necessary or desirable to be done in and about the premises, as fully to all intents and purposes as such person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them or his or their substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

In accordance with the Exchange Act, this report has been signed by the following persons on behalf of the registrant in the capacities indicated on April 14, 2003:

SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT.

An annual report will not be sent to security holders. No proxy material will be sent to security holders.

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.


	LSP BATESVILLE FUNDING CORPORATION
	(Registrant)

	/s/ RICHARD C. KELLY

	Richard C. Kelly
	President and Director

In accordance with the Exchange Act, this report has been signed by the following persons on behalf of the registrant in the capacities indicated on April 14, 2003:

SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT.

An annual report will not be sent to security holders. No proxy material will be sent to security holders.

1. I have reviewed this annual report on Form 10-K of LSP Energy Limited Partnership and LSP Batesville Funding Corporation;

2. Based on my knowledge, this annual 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 annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual 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 annual 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 annual 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 annual report (the “Evaluation Date”); and

	c) presented in this annual 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.

1. I have reviewed this annual report on Form 10-K of LSP Energy Limited Partnership and LSP Batesville Funding Corporation;


	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 annual 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 annual report (the “Evaluation Date”); and

	c) presented in this annual 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


*	Incorporated herein by reference from the Registration Statement on Form S-4, File No.’s 333-84609 and 333-84609-01, filed with the Securities and Exchange Commission by LSP Energy Limited Partnership and LSP Batesville Funding Corporation on March 6, 2000.

**	Incorporated herein by reference from the Quarterly Reports on Form 10-Q, File No.’s 333-84609 and 333-84609-01, filed with the Securities and Exchange Commission by LSP Energy Limited Partnership and LSP Batesville Funding Corporation on May 15, 2000, August 14, 2000 and November 14, 2000.


***	Incorporated herein by reference from the Annual Reports on Forms 10-K, File No.’s 333-84609 and 333-84609-01, filed with the Securities and Exchange Commission by LSP Energy Limited Partnership and LSP Batesville Funding Corporation on April 2, 2001.


þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		For the Fiscal Year Ended December 31, 2002.

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		For the Transition Period from to .


Delaware		22-3422042
Delaware		22-3615403
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

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


PART I
	Item 1 -- Business
	Item 2 -- Properties
	Item 3 -- Legal Proceedings
	Item 4 -- Submission of Matters to a Vote of Security Holders
PART II
	Item 5 -- Market for Registrant’s Common Equity and Related Stockholder Matters
	Item 6 -- Selected Financial Data
	Item 7 -- Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Item 7A -- Quantitative and Qualitative Disclosure about Market Risk
	Item 8 -- Financial Statements and Supplementary Data
	Item 9 -- Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
PART III
	Item 10 -- Directors and Executive Officers of the Registrant
	Item 11 -- Executive Compensation
	Item 12 -- Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
	Item 13 -- Certain Relationships and Related Transactions
	Item 14 -- Controls and Procedures
PART IV
	Item 15 -- Exhibits, Financial Statement Schedules and Reports on Form 8-K
	Item 15(a)(1) Financial Statements
INDEX TO THE FINANCIAL STATEMENTS
SIGNATURES
POWER OF ATTORNEY
POWER OF ATTORNEY
CERTIFICATIONS
EXHIBIT INDEX
Certification


		Page
		No.

PART I
Item 1	Business		2
Item 2	Properties		8
Item 3	Legal Proceedings		8
Item 4	Submission of Matters to a Vote of Security Holders		8
PART II
Item 5	Market for Registrants’ Common Equity and Related Stockholder Matters		8
Item 6	Selected Financial Data		8
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations		8
Item 7A	Quantitative and Qualitative Disclosure About Market Risk		18
Item 8	Financial Statements and Supplementary Data		18
Item 9	Changes in & Disagreements With Accountants on Accounting and Financial Disclosure		18
PART III
Item 10	Directors and Executive Officers of the Registrants		19
Item 11	Executive Compensation		19
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		19
Item 13	Certain Relationships and Related Transactions		19
Item 14	Controls and Procedures		19
PART IV
Item 15	Exhibits, Financial Statement Schedules, and Reports on Form 8-K		20
SIGNATURES			62


Accounting Policy		Judgments/Uncertainties Affecting Application

Capitalization Practices/Purchase Accounting		• Determination of beginning and ending of capitalization periods
		• Allocation of purchase prices to identified assets


	*For the Year Ended December 31, 2002 Compared to the Year Ended December 31, 2001*


	*For the Year Ended December 31, 2001 Compared to the Year Ended December 31, 2000*


Accounting Policy		Judgments/Uncertainties Affecting Application

Asset Valuation and Impairment		• Recoverability of investment through future operations
		• Regulatory and political environments and requirements
		• Estimated useful lives of assets
		• Environmental obligations and operational limitations
		• Estimates of future cash flows
		• Estimates of fair value
		• Judgment about triggering events
Revenue Recognition		• Customer/counter-party dispute resolution practices
		• Market maturity and economic conditions
		• Contract interpretation
Uncollectible Receivables		• Economic conditions affecting customers, counter parties, suppliers and market prices
		• Regulatory environment and impact on customer financial condition
		• Outcome of litigation and bankruptcy proceedings
Litigation Claims and Assessments		• Impacts of court decisions
		• Estimates of ultimate liabilities arising from legal claims


	Liquidity Issues of NRG Energy and Its Subsidiaries — Current Status and Chain of Events


	The Partnership and Funding Indebtedness and Liquidity Issues



	For the Year Ended December 31,

	2002			2001		2000


	(In thousands)
Net cash (used in)/provided by operating activities	$	(204	)	$	20,051	$	(10,733	)



	Payments Due by Period as of
	and Subsequent to December 31, 2002

	Total		Short Term		1-3 Years		4-5 Years		After 5 Years


	(Thousands of dollars)
Long term debt	$	314,300	$	7,125	$	17,175	$	24,450	$	265,550

Total contractual cash obligations	$	314,300	$	7,125	$	17,175	$	24,450	$	265,550


Item 10 —	*Directors and Executive Officers of the Registrant*


Item 12 —	*Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters*


Item 13 —	*Certain Relationships and Related Transactions*


	*Environmental Regulation*


	*Energy Regulation*


	*Overview*


	*Industry Dynamics*


LSP Batesville Funding Corporation:
	Balance Sheets — December 31, 2002 and 2001	24
	Statements of Operations — December 31, 2002, 2001 and 2000	25
	Statements of Changes in Stockholder’s Equity (Deficit) — December 31, 2002, 2001 and 2000	26
	Statements of Cash Flows — December 31, 2002, 2001 and 2000	27
	Notes to Financial Statements	28
LSP Energy Limited Partnership:
	Consolidated Balance Sheets — December 31, 2002, and 2001	36
	Consolidated Statements of Operations — December 31, 2002, 2001 and 2000	37
	Consolidated Statements of Changes in Partners’ Capital (Deficit) — December 31, 2002, 2001 and 2000	38
	Consolidated Statements of Cash Flows — December 31, 2002, 2001 and 2000	39
	Notes to Financial Statements	40


Title		Page

LSP Batesville Funding Corporation:
	Independent Auditors’ Report — PwC		22
	Independent Auditors’ Report — KPMG		23
	Balance Sheets as of December 31, 2002 and 2001		24
	Statements of Operations for the years ended December 31, 2002, 2001 and 2000		25
	Statements of Changes in Stockholder’s Equity (Deficit) for the years ended December 31, 2002, 2001 and 2000		26
	Statements of Cash Flows for the years ended December 31, 2002, 2001 and 2000		27
	Notes to Financial Statements		28
LSP Energy Limited Partnership:
	Independent Auditors’ Report — PwC		34
	Independent Auditors’ Report — KPMG		35
Consolidated Balance Sheets as of December 31, 2002, and 2001			36
Consolidated Statements of Operations for the years ended December 31, 2002, 2001 and 2000			37
Consolidated Statements of Changes in Partners’ Capital (Deficit) for the years ended December 31, 2002, 2001 and 2000			38
Consolidated Statements of Cash Flows for the years ended December 31, 2002, 2001 and 2000			39
Notes to Financial Statements			40



			December 31,

			2002			2001


			(In thousands)
ASSETS
Current assets
	Cash and cash equivalents		$	—		$	—

Total assets			$	—		$	—


LIABILITIES AND STOCKHOLDER’S DEFICIT
Current liabilities
	Accounts payable-affiliates		$	11		$	10
		Total liabilities		11			10
Commitments and contingencies
Stockholder’s deficit				(11	)		(10	)

Total liabilities and stockholder’s deficit			$	—		$	—



		Year Ended
		December 31,

		2002			2001		2000


		(In thousands)
Operating revenues
	Revenues from wholly-owned operations	$	—		$	—	$	—
Operating costs and expenses
	Operating costs		—			—		—
	Depreciation		—			—		—
	General and administrative expenses		2			—		5

Operating loss			(2	)		—		(5	)
Other income (expense)
	Other income, net		—			—		—
	Interest expense		—			—		—

Net loss		$	(2	)	$	—	$	(5	)


									Total
		Common		Additional		Accumulated			Stockholder’s
		Stock		Paid-In-Capital		Deficit			Deficit


		(In thousands)
Balance at December 31, 1999				$	1	$	(6	)	$	(5	)

	Net Loss		—		—		(5	)		(5	)

Balance at December 31, 2000				$	1	$	(11	)	$	(10	)

	Net Loss		—		—		—			—
	Capital contributions, net		—		—		—			—

Balance at December 31, 2001				$	1	$	(11	)	$	(10	)

	Net Loss		—		—		(2	)		(2	)
	Capital contributions, net		—		1		—			1

Balance at December 31, 2002				$	2	$	(13	)	$	(11	)


	Amounts

2003	$	7,125,000
2004		7,575,000
2005		9,600,000
2006		11,925,000
2007		12,525,000
Thereafter		265,550,000

Total	$	314,300,000



		Year Ended December 31,

		2002			2001			2000


		(In thousands)
Operating revenues
	Operating revenues	$	53,211		$	52,512		$	20,385
Operating costs and expenses
	Operating costs		20,271			8,784			6,041
	Depreciation		14,415			14,292			5,793
	General and administrative expenses		739			770			374

Operating income			17,786			28,666			8,177

Other income (expense)
	Interest income		678			1,692			2,174
	Interest expense		(24,963	)		(25,444	)		(11,204	)

Net (loss)/income		$	(6,499	)	$	4,914		$	(853	)


		99%
		Limited Partner			1%
		LSP Batesville			General Partner			Total Partners’
		Holding, LLC			LSP Energy, Inc.			Capital (Deficit)


		(In thousands)
Balance at December 31, 1999		$	(3,121	)	$	(31	)	$	(3,152	)

	Capital contributions, net		54,000			—			54,000
	Distributions to partners’		(7,248	)		—			(7,248	)
	Net loss		(843	)		(10	)		(853	)

Balance at December 31, 2000		$	42,788		$	(41	)	$	42,747

	Net income		4,865			49			4,914

Balance at December 31, 2001		$	47,653		$	8		$	47,661

	Net loss		(6,454	)		(45	)		(6,499	)

Balance at December 31, 2002		$	41,199		$	(37	)	$	41,162


Note 6 —	Derivative Instruments and Hedging Activity



Signature				Title

/s/ RICHARD C. KELLY Richard C. Kelly				President (Principal Executive Officer) and Director

/s/ GEORGE SCHAEFER George Schaefer				Treasurer (Principal Financial Officer)

/s/ SCOTT J. DAVIDO Scott J. Davido				Vice President and Director

/s/ ANDREW STIDD Andrew Stidd				Director

/s/ WILLIAM T. PIEPER William T. Pieper				Controller (Principal Accounting Officer)


***2.1	—	Purchase Agreement, dated as of November 3, 2000, among NRG Energy, Inc., NRG Granite Acquisition LLC, LS Power, LLC, CB Capital Investors, LLC, Cogen Grantor Trust UA and Granite Power Partners II, L.P.
***2.2	—	Securities Purchase Agreement, dated as of February 6, 2001, as amended by the First Amendment dated as of March 14, 2001, between NRG Energy, Inc. and Cogentrix/ Batesville, LLC.
*3.1	—	Amended and Restated Certificate of Incorporation of LSP Batesville Funding Corporation.
*3.2	—	Amended and Restated Limited Partnership Agreement of LSP Energy Limited Partnership.
*3.3	—	By-Laws of LSP Batesville Funding Corporation.
*3.4	—	Certificate of Limited Partnership of LSP Energy Limited Partnership.
*4.1	—	Indenture, dated as of May 21, 1999, among LSP Batesville Funding Corporation, LSP Energy Limited Partnership and the Bank of New York, as trustee.
*4.2	—	First Supplemental Indenture, dated as of May 21, 1999, among LSP Batesville Funding Corporation, LSP Energy Limited Partnership and The Bank of New York, as Trustee, relating to $150,000,000 aggregate principal amount of 7.164% Series A Senior Secured Bonds due 2014.
*4.3	—	Second Supplemental Indenture, dated as of May 21, 1999, among LSP Batesville Funding Corporation, LSP Energy Limited Partnership and The Bank of New York, as Trustee, relating to $176,000,000 aggregate principal amount of 8.160% Series B Senior Secured Bonds due 2025.
***4.4	—	Third Supplemental Indenture, dated as of April 11, 2000 among LSP Batesville Funding Corporation, LSP Energy Limited Partnership and The Bank of New York, as Trustee, relating to $150,000,000 aggregate principal amount of 7.164% Series C Senior Secured Bonds due 2014.†
***4.5	—	Fourth Supplemental Indenture, dated as of April 11, 2000, among LSP Batesville Funding Corporation, LSP Energy Limited Partnership and The Bank of New York, as Trustee, relating to $176,000,000 aggregate principal amount of 8.160% Series D Senior Secured Bonds due 2025.†
*4.6	—	Specimen Certificate of 7.164% Series A Senior Secured Bonds due 2014.
*4.7	—	Specimen Certificate of 8.160% Series B Senior Secured Bonds due 2025.
***4.8	—	Specimen Certificate of 7.164% Series C Senior Secured Bonds due 2014.
***4.9	—	Specimen Certificate of 8.160% Series D Senior Secured Bonds due 2025.
*4.10	—	Exchange and Registration Rights Agreement, dated as of May 21, 1999, among LSP Batesville Funding Corporation, LSP Energy Limited Partnership, Credit Suisse First Boston Corporation, Scotia Capital Markets (USA) Inc. and TD Securities (USA) Inc.
*4.11	—	Second Amended and Restated Common Agreement, dated as of May 21, 1999, among LSP Batesville Funding Corporation, LSP Energy Limited Partnership and The Bank of New York, as Collateral Agent, Administrative Agent and Intercreditor Agent.
*4.12	—	Intercreditor Agreement, dated as of May 21, 1999, among LSP Batesville Funding Corporation, LSP Energy Limited Partnership, Credit Suisse First Boston, as Dominion L/ C Agent, and The Bank of New York, as Collateral Agent, Trustee, Administrative Agent and Intercreditor Agent.
*4.13	—	Second Amended and Restated Equity Contribution Agreement, dated as of May 21, 1999, among LSP Batesville Holding, LLC, LSP Energy Limited Partnership and The Bank of New York, as Collateral Agent.
*4.14	—	Second Amended and Restated Collateral Agency Agreement, dated as of May 21, 1999, among LSP Batesville Funding Corporation, LSP Energy Limited Partnership, the Senior Secured Parties party thereto from time to time, The Bank of New York, as Administrative Agent, Collateral Agent and Intercreditor Agent, and Credit Suisse First Boston, as Additional Collateral Agent.
*4.15	—	Pledge and Security Agreement, dated as of May 21, 1999 (Funding Corporation’s Stock), between LSP Batesville Holding, LLC and The Bank of New York, as Collateral Agent.
*4.16	—	Second Amendment and Restated Pledge and Security Agreement (LSP Energy, Inc.’s Stock), dated as of May 21, 1999, between LSP Batesville Holding, LLC and The Bank of New York, as Collateral Agent.


*4.17	—	Second Amended and Restated Pledge and Security Agreement (Limited Partnership Interest in the Partnership), dated as of May 21, 1999, between LSP Batesville Holding, LLC and The Bank of New York, as Collateral Agent.
*4.18	—	Second Amended and Restated Pledge and Security Agreement (General Partnership Interest in the Partnership), dated as of May 21, 1999, between LSP Energy, Inc. and The Bank of New York, as Collateral Agent.
*4.19	—	Second Amended and Restated Security Agreement, dated as of May 21, 1999, between LSP Energy Limited Partnership and The Bank of New York, as Collateral Agent.
*4.20	—	Security Agreement, dated as of May 21, 1999, between LSP Batesville Funding Corporation and The Bank of New York, as Collateral Agent.
*4.21	—	Deed of Trust, Security Agreement, Assignment of Leases and Rents and Fixture Filing, dated as of May 21, 1999, by LSP Limited Partnership, as trustor, to James W. O’Mara, as trustee, for the benefit of The Bank of New York, as Collateral Agent.
*4.22	—	Second Amended and Restated Securities Account Control Agreement, dated as of May 21, 1999, among LSP Batesville Funding Corporation, LSP Energy Limited Partnership and The Bank of New York, as Collateral Agent and Securities Intermediary.
*10.1	—	Purchase Agreement, dated May 13, 1999, among LSP Energy Limited Partnership, LSP Batesville Funding Corporation, Credit Suisse First Boston Corporation, Scotia Capital Markets (USA) Inc. and TD Securities (USA) Inc.
*10.2	—	Power Purchase Agreement, dated May 18, 1998, and amendments thereto dated July 22, 1998 and August 11, 1998, among LSP Energy Limited Partnership and Virginia Electric and Power Company.
*10.3	—	Power Purchase Agreement, dated May 21, 1998, and amendments thereto dated July 14, 1998, July 16, 1998 and August 27, 1998, among LSP Energy Limited Partnership, Aquila Energy Marketing Corporation and Utilicorp United Inc.
*10.4	—	Interconnection Agreement, dated July 22, 1998, between LSP Energy Limited Partnership and the Tennessee Valley Authority.
*10.5	—	Interconnection and Operating Agreement, dated May 18, 1998, and amendment thereto dated August 18, 1998, between LSP Energy Limited Partnership and Entergy Mississippi, Inc.
*10.6	—	Interconnection Agreement, dated July 28, 1998, between LSP Energy Limited Partnership and ANR Pipeline Company.
*10.7	—	Facilities Agreement, dated June 23, 1998, between Tennessee Gas Pipeline Company and LSP Energy Limited Partnership.
*10.8	—	Turnkey Engineering, Procurement and Construction Agreement, dated July 22, 1998, and amendments thereto dated July 22, 1998, October 22, 1998, November 2, 1998, November 5, 1998, December 10, 1998, February 1, 1999 and April 12, 1999, between LSP Energy Limited Partnership and BVZ Power Partners-Batesville.
*10.9	—	Engineering Services Agreement, dated July 24, 1998, between LSP Limited Partnership and Black & Veatch, LLP.
*10.10	—	Guaranty Agreement (EPC), dated as of July 22, 1998, by Black & Veatch, LLP in favor of LSP Energy Limited Partnership.
*10.11	—	Management Services Agreement, dated as of August 24, 1998, between LSP Energy Limited Partnership and LS Power Management, LLC.
*10.12	—	Operation and Maintenance Agreement, dated August 24, 1998, between LSP Energy Limited Partnership and Cogentrix Batesville Operations, LLC.
*10.13	—	Water Supply Storage Agreement, dated as of June 8, 1998, and amendment thereto dated March 15, 1999, between LSP Energy Limited Partnership and the United Sates of America.
*10.14	—	Parts Supply Letter Agreement/ Blanket Purchase Order, dated July 20, 1998, between LSP Energy Limited Partnership and Westinghouse Power Generation.
*10.15	—	Ad Valorem Tax Contract, dated as of August 24, 1998, among LSP Energy Limited Partnership, Panola County, Mississippi, the City of Batesville, Mississippi, the Department of Economic and Community Development and the Panola County Tax Assessor/ Collector.


*10.16	—	Letter of Credit and Reimbursement Agreement, dated as of August 28, 1998, among LSP Energy Limited Partnership, Credit Suisse First Boston, as the Dominion L/ C Agent and the Dominion L/ C Issuer, and the Dominion L/ C Banks.
*10.17	—	Infrastructure Use Agreement (Lateral Pipeline), dated as of August 12, 1999, among LSP Energy Limited Partnership, the Industrial Development Authority of the Second Judicial District of Panola County, Mississippi, the Mississippi Major Economic Impact Authority, Panola County, Mississippi and the City of Batesville, Mississippi.
*10.18	—	Inducement Agreement, dated as of August 12, 1999, among LSP Energy Limited Partnership, the Industrial Development Authority of the Second Judicial District of Panola County, Mississippi, the Mississippi Department of Economic and Community Development, the Mississippi Major Economic Impact Authority, Panola County, Mississippi and the City of Batesville, Mississippi.
*10.19	—	Panola Partnership Agreement, dated as of August 12, 1999, among LSP Energy Limited Partnership and Panola Partnership, Inc.
*10.20	—	Infrastructure Use Agreement (Water Supply System and Wastewater Disposal System), dated as of August 12, 1999, among LSP Energy Limited Partnership, the Industrial Development Authority of the Second Judicial District of Panola County, Mississippi, the Mississippi Major Economic Impact Authority, Panola County, Mississippi
*10.21	—	Yalobusha County Agreement, dated February 16, 1999, among LSP Energy Limited Partnership, Yalobusha County, Mississippi and the Coffeeville School District.
*10.22	—	Performance Bond and Payment Bond, dated August 13, 1998, of United States Fidelity and Guaranty Company, as surety.
**10.23	—	Power Purchase Agreement, dated February 23, 2000, between Tennessee Valley Authority and LSP Energy Limited Partnership.
**10.24	—	Facilities Interconnect, Construction, Ownership and Operation Agreement, dated January 28, 2000, between Trunkline Gas Company and LSP Energy Limited Partnership for M&R Panola County, Mississippi.
**10.25	—	First Amendment to Power Purchase Agreement, dated as of August 4, 2000, among LSP Energy Limited Partnership, Aquila Energy Marketing Corporation and Utilicorp United Inc.
**10.26	—	Second Amendment to Power Purchase Agreement dated as of August 11, 1998, and Third Amendment to Power Purchase Agreement dated as of August 9, 2000, each between LSP Energy Limited Partnership and Virginia Electric and Power Company.
**10.27	—	Escrow Agreement, dated as of August 17, 2000, among Virginia Electric and Power Company, LSP Energy Limited Partnership and The Chase Manhattan Bank.
***10.28	—	Fourth Amendment to Power Purchase Agreement, dated as of December 13, 2000, between LSP Energy Limited Partnership and Virginia Electric and Power Company.
***10.29	—	Letter Agreements, dated as of July 28, 1998 and December 12, 2000, among LSP Energy Limited Partnership, Aquila Power Corporation and Utilicorp United Inc.
***10.30	—	Letter Agreement, dated as of August 13, 1998, between LSP Energy Limited Partnership and Virginia Electric and Power Company.
***10.31	—	Settlement Agreement, dated as of December 13, 2000, between LSP Energy Limited Partnership and Virginia Electric and Power Company.
***10.32	—	Pipeline Balancing Agreement, dated February 14, 2000, between Tennessee Gas Pipeline Company and LSP Energy Limited Partnership.
***10.33	—	Industrial Power Contract, dated as of May 10, 2000, between Tallahatchie Valley Electric Power Association and LSP Energy Limited Partnership.
99.1	—	Officer Certification