DOCUMENTS INCORPORATED BY REFERENCE:   Current report on Form 8-K, dated August 7, 2002 regarding the change in registrant's certifying accountant

COGENTRIX ENERGY, INC.

INDEX TO ANNUAL REPORT ON FORM 10-K

Item 1.     Business

Introduction

          Cogentrix Energy, Inc. is an independent power producer that through its direct and indirect subsidiaries acquires, develops, owns and operates electric generating plants. We derive most of our revenue from the sale of electricity, but we also produce and sell steam. We sell the electricity we generate to regulated electric utilities and power marketers, primarily under long-term power purchase agreements or conversion services agreements. We sell the steam we cogenerate to industrial customers with manufacturing or other facilities located near our electric generating plants. We were one of the early participants in the market for electric power generated by independent power producers that developed as a result of energy legislation the United States Congress enacted in 1978. We believe we are one of the larger independent power producers in the United States based on our total project megawatts in operation.

          We currently own - entirely or in part - a total of 26 electric generating facilities in the United States and one in the Dominican Republic. Our 27 plants are designed to operate at a total production capability of approximately 7,695 megawatts. After taking into account our partial interests in the 19 plants that are not wholly-owned by us, which range from 1.6% to approximately 74.2%, our net ownership interests in the total production capability of our 27 electric generating facilities is approximately 4,889 megawatts. We currently operate 14 of our facilities, 12 of which we developed and constructed.

          Unless the context requires otherwise, references in this report to "we", "us", "our", or "Cogentrix" refer to Cogentrix Energy, Inc. and its subsidiaries, including subsidiaries that hold investments in other corporations or partnerships whose financial results are not consolidated with ours. The term "Cogentrix Energy" refers only to Cogentrix Energy, Inc., which is a development and management company that conducts its business primarily through subsidiaries. Cogentrix Energy's subsidiaries that are engaged in the development, ownership or operation of cogeneration facilities are sometimes referred to individually as a "project subsidiary" and collectively as "project subsidiaries." The unconsolidated affiliates of Cogentrix Energy that are engaged in the ownership and operation of electric generating facilities and in which we have less than a majority interest are sometimes referred to individually as a "project affiliate" or collectively as "project affiliates."

Our Strategy

          We intend to remain as one of the independent power industry leaders in the operation of electric generating facilities. We will seek to maximize the power generation potential of our operating assets and to minimize our operations and maintenance expenses and our fuel costs. These efforts encompass a commitment to upholding superior standards of safety, environmental compliance and efficiency. We focus on operating our plants under an integrated system which encourages the sharing of key information and best practices and enables us to minimize costs and maximize operating efficiencies. We believe that maintaining a low cost of production will be increasingly important to compete effectively in our business. In addition, we will assess restructuring alternatives for our existing power sale contracts that will enhance revenue generation or minimize variable operating costs.

          To supplement our existing fleet of facilities we will assess opportunities to develop or acquire additional electric generating facilities on a very selective basis. The primary elements of our growth strategy are as follows:

Trends Affecting the Electric Generating Industry

          During 2002, the electric power generation industry experienced a number of adverse trends and events that will limit our ability to develop or acquire electric generating facilities. These trends and events included:

Project Agreements, Financing and Operating Arrangements for Our Operating Facilities

     Project Agreements

          Most of our facilities have long-term power sales agreements to sell electricity to electric utilities or long-term conversion services agreements to sell conversion services (whereby our customers provide fuel to our facilities and our facilities convert this fuel into electricity) to power marketers. A facility's revenue from a power sales or conversion services agreement usually consists of two components: variable payments, which vary in accordance with the amount of energy the facility produces, and fixed payments that are received in the same amounts whether or not the facility is producing energy. Variable payments, which are generally intended to cover the costs of actually generating electricity, such as fuel costs if supplied by the operating facility and variable operation and maintenance expense, are based on a facility's net electrical output measured in kilowatt hours. Variable payment rates are either scheduled or indexed to the fuel costs of the electricity purchaser and/or an inflationary index.

          Fixed payments, which are intended to compensate us for the costs incurred by the project subsidiary whether or not it is generating electricity, such as debt service on the project financing, are more complex and are calculated based on a declared production capability of a facility. Declared production capability is the electric generating capability of a plant in megawatts that the project subsidiary contractually agrees to make available to the electricity purchaser. It is generally close to, but slightly less than 100% of the facility's design production capability dictated by its equipment and design specifications. Fixed payments are based either on a facility's net electrical output and paid on a kilowatt-hour basis or on the facility's declared production capability and can be adjusted if actual production capability varies significantly from declared production capability.

          Our power sales and conversion services agreements permit the electricity purchaser to direct the facility to deliver a variable amount of electrical output within limited parameters. This means the purchaser may, within those parameters, direct the facility to reduce or suspend the delivery of electricity. The power sales and conversion services agreements of substantially all of our facilities provide the electricity and conversion services purchaser with the right to reduce or suspend their purchases or delivery of electricity whenever they determine that they can obtain lower cost power either by generating power at their own plants or by purchasing electricity in bulk from others. The power sales and conversion services agreements for these facilities are structured in a manner such that when the amount of electrical output is reduced, the facility continues to receive the fixed payments, which cover fixed operating costs and debt service requirements and provide substantially all of the project subsidiary's profits. The variable payments, which cover the operating, maintenance and fuel costs incurred by the project subsidiary to generate electricity, are received only for each kilowatt-hour delivered.

          Many of our facilities produce process steam for use by an industrial customer that has a manufacturing or other facility located nearby. Our industrial customers, which include textile manufacturing companies, pharmaceutical manufacturing companies, chemical producers and synthetic fiber plants, use the process steam in their manufacturing processes. Our steam sales contracts with these industrial customers generally are long-term contracts that provide payment on a per thousand pound basis for steam delivered.

          With the exception of facilities that the conversion services purchaser is responsible for providing fuel, most of our facilities purchase fuel under long-term supply agreements. Substantially all fuel supply contracts are structured so that the scheduled increases in the fuel cost are generally matched by increases in the variable payments received by the project subsidiary for electricity under its power sales agreements and, if applicable, steam under its steam sales agreements. This matching is typically accomplished by escalating the fuel prices as a function of the solid fuel index of the electricity purchaser by contracting for scheduled increases in the variable payments under our power sales or steam sales agreements designed to offset scheduled increases in fuel prices.

     Project Financing

          Each facility is or was financed primarily under financing arrangements at the project subsidiary or project affiliate level that, except as noted below, require the loans to be repaid solely from the project subsidiary's or project affiliate's revenues. They also generally provide that the repayment of the loans and payment of interest is secured solely by the physical assets, agreements, cash flow and, in certain cases, the capital stock of our partnership or membership interests in that project subsidiary or project affiliate. This type of financing is generally referred to as "project financing."

          Project financing transactions are generally structured so that all revenues of a project are deposited directly with a bank or other financial institution acting as escrow or security deposit agent. These funds are then payable in a specified order of priority to assure that, to the extent available, they are used first to pay operating expenses, senior debt service, taxes and to fund reserve accounts. Then, subject to satisfying debt service coverage ratios and other conditions, any available funds may be disbursed to Cogentrix Energy and its other partners in the case of jointly owned facilities in the form of management fees, dividends, or distributions.

          Our facilities are initially financed using a high proportion of debt to equity. This leveraged financing permits our project subsidiaries and project affiliates to develop projects with a limited equity base but also increases the risk that a reduction in revenues could adversely affect a particular project's ability to meet its debt obligations. The lenders to each project subsidiary or project affiliate have security interests covering some or all of the aspects of the project, including the facility, related facility support agreements, the stock or partnership interest of our project subsidiaries or project affiliates, licenses and permits necessary to operate the facility and the cash flow derived from the facility. In the event of a foreclosure after a default, the project subsidiary or project affiliate would only retain an interest in the property remaining, if any, after all debts and obligations were paid.

          In addition, the debt of each operating project may reduce the liquidity of our interest in such project since any sale or transfer of its interest would, in most cases, be subject both to a lien securing such project debt and to transfer restrictions in the relevant financing agreements. Also, our ability to transfer or sell our interest in some of our projects is restricted by purchase options or rights of first refusal we have granted in favor of certain of our power purchasers, steam purchasers and project partners.

          Because the project debt is "non-recourse," the lenders under these project financing structures cannot look to Cogentrix Energy or its other projects for repayment unless Cogentrix Energy or another project subsidiary expressly agrees to undertake liability. Cogentrix Energy has agreed to undertake limited financial support for certain of its project subsidiaries in the form of limited obligations and contingent liabilities. These obligations and contingent liabilities take the form of guarantees, indemnities, capital infusions, support agreements and agreements to pay debt service deficiencies. To the extent Cogentrix Energy becomes liable under such guarantees and other agreements with respect to a particular project, the lenders to the project may look to use distributions received by Cogentrix Energy from other projects to satisfy these obligations. The aggregate contractual liability of Cogentrix Energy to the project lenders is, in each case, a small portion of the aggregate project debt. Thus, the project financing structures are generally described throughout this report as being "non-recourse" to Cogentrix Energy and its other projects.

          Two of our wholly-owned subsidiaries, Cogentrix Mid-America, Inc. ("Mid-America") and Cogentrix Eastern America, Inc. ("Eastern America"), which were formed to hold our interests in the entities which hold interests in the electric generating facilities we acquired in 1999 and 1998, maintain their own credit agreements with banks. Distributions received by Mid-America from the project subsidiaries they own or hold an interest in may be used to satisfy any outstanding obligations under their credit facility. In addition, distributions received by Eastern America from four of the significant project affiliates it holds an interest in may be used to satisfy outstanding obligations under their credit facility. Eastern America, which amended its credit agreement in September 2002, is currently required to accumulate up to $6.0 million in escrow from the distributions Eastern America receives from four of the significant project affiliates. Eastern America may be required to use those escrowed amounts as well as any future distributions from those project affiliates to pay down the outstanding balance under its revolving credit agreement in the event certain conditions exist. See "Management's Discussion and Analysis of Financial Condition and Results of Operation -Liquidity and Capital Resources - Cash Flow from Our Project Subsidiaries and Project Affiliates - Cogentrix Eastern America."

          Our facilities are insured in accordance with covenants in each project's debt financing agreements or to the satisfaction of the project lenders. Coverages for each plant include workers' compensation, commercial general liability, supplemented by primary and excess umbrella liability, and a master property insurance program including property, boiler and machinery and business interruption.

     Operating Arrangements

          We operate fourteen of our facilities. When we operate a facility, our project subsidiary or project affiliate directly employs the personnel required to operate the facility. We invest in training our operating personnel and structure our facility bonus program to reward safe, efficient and cost-effective operation of the facilities. Our management meets and conducts, several times a year, on-site facility performance reviews with each facility manager.

          We have established a strong record of safety, efficiency and reliability in operating our electric generating facilities, which reliability is measured in the industry by a generating plant's "availability" to generate and sell electricity. The table below shows the average "availability" of the plants we operated during the periods indicated.

          We provide to the facilities we operate administrative and management services for a periodic fee that in some cases is adjusted annually by an inflation factor. The ability of a project subsidiary or project affiliate to pay these management fees is contingent upon the continuing compliance by the project subsidiary or project affiliate with covenants under its project financing agreements and may be subordinated to the payment of obligations under those agreements.

     Ash Removal

          Project subsidiaries owning six of our coal-fired plants contract with our subsidiary, ReUse Technology, Inc., to remove coal combustion by-products generated by such facilities. ReUse constructs structural fills with these coal combustion by-products on property owned by it and others and provides coal combustion by-products to others for use in manufacturing and producing various products for resale.

Facilities In Operation

          Our facilities described below rely on power purchase or conversion services agreements for the majority of their revenues. During the fiscal year ended December 31, 2002, two regulated utility customers, Dominion Virginia Power and Florida Power & Light, accounted for approximately 36% and 14%, respectively of our interest in the aggregate revenues of our project subsidiaries and project affiliates. We expect that Dominion Virginia Power will account for a smaller portion of our revenue base in the future as a result of a significant reduction in fixed payments we are receiving from this utility at our Hopewell and Portsmouth facilities since December 31, 2002. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Events and Trends Affecting Our Financial Condition and Results of Operations - Termination or Modification of Certain Power Sales Agreements at Some of Our Facilities." The failure of either of these utility customers to fulfill its contractual obligations for a prolonged period of time would have a material adverse effect on our primary source of revenues. Both of the regulated utilities have senior, unsecured debt outstanding that the major credit rating agencies have rated investment grade. Our Sterlington, Jenks, Dominican Republic and Rathdrum facilities all achieved commercial operations during 2001 and 2002. In addition, the Southaven and Caledonia facilities began producing power during early 2003, and we expect they will commence commercial operations in mid-2003.

Description of Facilities in Which We Own a Significant Economic Interest

     Jenks, Oklahoma Facility

          Our 810-megawatt combined-cycle, natural gas-fired electric generating facility located in Jenks, Oklahoma, provides declared production capability of up to 795 megawatts to Exelon Generating Company under a conversion services agreement that expires in February 2022. Exelon Generating Company is required to provide natural gas to the facility and we are required to convert the delivered fuel into electricity at a guaranteed efficiency. The facility's operation above or below this guaranteed efficiency will result in bonus or penalty payments from or to a tracking account. Exelon Generating Company has the exclusive right to dispatch the facility and is obligated to accept the entire electrical output of the facility as dispatched. Our project subsidiary has posted a letter of credit in favor of Exelon Generating Company to secure its obligations under the conversion services agreement.

          Fixed payments are subject to reduction to the extent the facility is unable to provide availability levels required under the conversion services agreement. We have the option to provide replacement power to Exelon Generating Company in lieu of reduced fixed payments. The contract capacity is subject to an adjustment on the basis of annual capacity testing.

     Southaven Facility

          Our 810-megawatt combined-cycle, natural gas-fired electric generating facility located in Southaven, Mississippi is being constructed to provide declared production capacity of at least 735 megawatts to PG&E Energy Trading-Power, L.P. ("PGET") under a 20-year conversion services agreement that will begin on the commercial operations date. The facility is currently in the testing phase and is scheduled to achieve commercial operations in mid-2003. On February 27, 2003 our project subsidiary for the Southaven facility notified the lender of an event of default under the facility's non-recourse loan agreement that resulted from an earlier downgrade of the credit ratings of PG&E National Energy Group, Inc. ("NEG"), the parent of PGET and the guarantor of PGET's obligations under the conversion services agreement. We do not anticipate, however, based upon discussions with the lender, that this event of default will result in an interruption of funding construction draws or a delay in the construction schedule of the Southaven facility. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Cash Flow from Our Project Subsidiaries and Project Affiliates - Caledonia and Southaven Facility Defaults."

          PGET is required to provide natural gas to the facility and we are required to convert the delivered fuel into electricity at a guaranteed efficiency. The facility's operation above or below this guaranteed efficiency will result in bonus or penalty payments. Fixed payments are subject to reduction to the extent the facility is unable to provide net electric output as dispatched. We have the option to provide replacement power to PGET in lieu of reduced fixed payments.

          PGET is currently seeking to terminate the conversion services agreement and we are disputing PGET's right to do so. In March 2003, a Maryland court ordered PGET to submit the dispute to binding arbitration and to perform its obligations under the conversion services agreement during the arbitration proceedings. On March 24, 2003, PGET issued a Demand for Arbitration before the American Arbitration Association to resolve the disputes between the parties concerning PGET's alleged default by our project subsidiary under the conversion services agreement and PGET's disputed termination based upon that disputed default. If PGET terminates the agreement or otherwise does not perform under the agreement, it is our intention to operate the Southaven facility with one or more replacement agreements and/or as a merchant plant. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Cash Flow from Our Project Subsidiaries and Project Affiliates - Caledonia and Southaven Facility Defaults" for additional information regarding the potential contract termination and the impact it would have on this facility.

     Caledonia Facility

          Our 810-megawatt combined-cycle, natural gas-fired electric generating facility located in Caledonia, Mississippi is being constructed to provide declared production capacity of at least 735 megawatts to PGET under a 25-year conversion services agreement which will begin on the commercial operations date. The facility is currently in the testing phase and is scheduled to achieve commercial operations in mid-2003. On February 27, 2003 our project subsidiary for the Caledonia facility notified the lender of an event of default under the facility's non-recourse loan agreement that resulted from an earlier downgrade of the credit ratings of NEG, the parent of PGET and the guarantor of PGET's obligations under the conversion services agreement. We do not anticipate, however, based upon discussions with the lender, that this event of default under the project loan agreement will result in an interruption of funding construction draws or a delay in the construction schedule of the Caledonia facility. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Cash Flow from Our Project Subsidiaries and Project Affiliates - Caledonia and Southaven Facility Defaults."

          PGET is required to provide natural gas to the facility and we are required to convert the delivered fuel into electricity at a guaranteed efficiency. The facility's operation above or below this guaranteed efficiency will result in bonus or penalty payments. Fixed payments are subject to reduction to the extent the facility is unable to provide net electric output as dispatched. We have the option to provide replacement power to PGET in lieu of reduced fixed payments.

          PGET is currently seeking to terminate the conversion services agreement and we are disputing PGET's right to do so. In March 2003, a Maryland court ordered PGET to submit the dispute to binding arbitration and to perform its obligations under the conversion services agreement during the arbitration proceeding. On March 24, 2003, PGET issued a Demand for Arbitration before the American Arbitration Association to resolve the disputes between the parties concerning PGET's alleged default by our project subsidiary under the conversion services agreement and PGET's disputed termination based upon that disputed default. If PGET terminates the agreement or otherwise does not perform under the agreement, it is our intention to operate the Caledonia facility with one or more replacement agreements and/or as a merchant plant. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Cash Flow from Our Project Subsidiaries and Project Affiliates - Caledonia and Southaven Facility Defaults" for additional information regarding the potential contract termination and the impact it would have on this facility.

     Sterlington, Louisiana Facility

          Our 816-megawatt combined-cycle, natural gas-fired electric generating facility located near the city of Sterlington, Louisiana provides declared production capability of up to 816 megawatts to Dynegy Power Marketing, Inc. under a conversion services agreement that has an initial expiration in September 2012. Either Dynegy Power Marketing, Inc. or our project affiliate has the option to extend this agreement for an additional five years. One of our wholly-owned subsidiaries owns 50% of the facility and a wholly-owned subsidiary of General Electric Capital Corporation ("GECC") owns the other 50% of the facility. Dynegy Power Marketing, Inc. is required to provide natural gas to the facility and we are required to convert the delivered fuel into electricity at a guaranteed efficiency. The facility's operation above or below this guaranteed efficiency will result in bonus or penalty payments from or to a tracking account. Dynegy Power Marketing, Inc. has the exclusive right to dispatch the facility and is obligated to accept the entire electrical output of the facility as dispatched. Cogentrix Energy has provided an unsecured guarantee of up to $5.0 million to support the obligations of our project affiliate under its conversion services agreement. GECC has agreed to reimburse Cogentrix Energy for 50% of any amounts Cogentrix Energy is required to pay under this guarantee up to $2.5 million.

          Fixed payments are subject to reduction to the extent the facility is unable to provide availability levels required under the conversion services agreement. We have the option to provide replacement power to Dynegy Power Marketing, Inc. in lieu of reduced fixed payments. The contract capacity is subject to an adjustment on the basis of annual capacity testing.

          Our project affiliate for the Sterlington Facility is currently in default under its non-recourse loan agreement, and we will not receive distributions from this project affiliate until we can refinance the non-recourse project financing for this facility. This event of default occurred as the result of the loss of investment grade credit ratings in July 2002 by Dynegy Holdings, Inc. ("Dynegy"), the guarantor of the obligations of Dynegy Power Marketing, Inc., which triggered an event of default under the conversion services agreement when Dynegy failed to cure this event of default in the time period provided. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Cash Flow from Our Project Subsidiaries and Project Affiliates - Sterlington Facility."

     Richmond, Virginia Facility

          Our 240-megawatt stoker coal-fired cogeneration plant in Richmond, Virginia provides 209 megawatts of declared production capability to Dominion Virginia Power under two 25-year power sales agreements both of which expire in 2017. Our Richmond facility also provides steam to E. I. du Pont de Nemours & Company.

          Each of the power sales agreements provides that in the event the state utilities commission prohibits Dominion Virginia Power from recovering from its customers payments made by Dominion Virginia Power to our project subsidiary, our subsidiary would recognize a reduction in payments received under such power sales agreements after the 18th anniversary of commencement of commercial operations of the facility to the extent necessary to repay the amount of the disallowed payments to Dominion Virginia Power with interest.

          If the number of days in any year in which the Richmond facility is unable to generate electricity in an amount equal to its declared production capability is more than the greater of 25 days or ten percent of the total number of days the facility was required by Dominion Virginia Power to operate, the fixed payments under the contract for that period will be reduced by four percent for each excess day. In the event capacity testing indicates that the facility's dependable production capability is less than 90% of the declared production capability, our subsidiary will be obligated to pay annual liquidated damages to Dominion Virginia Power. Our project subsidiary has posted letters of credit in favor of Dominion Virginia Power to secure its obligations to perform under the power sales agreements.

     Dominican Republic Facility

          Our Dominican Republic facility is a 300-megawatt, combined-cycle, oil-fired electric generating facility in San Pedro de Macorís, Dominican Republic. One of our wholly-owned subsidiaries owns 65% of the facility and a wholly-owned subsidiary of the Commonwealth Development Corporation, a quasi-governmental entity owns the remaining 35% of the facility.

          The Dominican Republic facility is a three-unit facility that provides approximately 295 megawatts of declared production capability to Corporación Dominicana de Electricidad ("CDE") under a power purchase agreement that expires in March 2022. The three units attained commercial operations between November 2001 and March 2002. The contract capacity is subject to an adjustment based on a semi-annual capacity test. CDE has the exclusive right to dispatch the facility and is obligated to accept the entire net electric output of the facility. Our project subsidiary posted a $10.0 million letter of credit to support its obligations under this power purchase agreement in conjunction with the entire facility being declared commercial. Cogentrix Energy has provided a reimbursement obligation related to 65% of this letter of credit. The State of the Dominican Republic has guaranteed the CDE's payment obligations to our project subsidiary through an implementation agreement unanimously ratified by the full Dominican Congress.

          Since August 2002, CDE has failed to pay significant amounts due to our project subsidiary for the sale of capacity and electricity. The payment defaults currently total approximately $30.8 million. As a result of these payment defaults by CDE and the State of the Dominican Republic's failure to honor its guarantee of CDE's obligations, our project subsidiary has suspended operation of this facility until CDE cures the payment defaults. In addition, as a result of these payment defaults, the Dominican Republic facility triggered two events of default of its non-recourse project financing. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Cash Flow from Our Project Subsidiaries and Project Affiliates - Dominican Republic Facility."

          Our project subsidiary is required to pay liquidated damages to CDE in the event we incur greater than 888 hours (total, hours measured per unit) of forced outage, maintenance outage and scheduled outage hours in any billing year in which a major overhaul is not performed. During a billing year in which a major overhaul is performed, we will be required to pay liquidated damages if we incur greater than 1,320 hours of forced outage, maintenance outage, scheduled outage and major overhaul outage hours.

     Indiantown, Florida Facility

          A Delaware limited partnership owns this 380-megawatt pulverized coal-fired cogeneration facility located in Martin County, Florida. NEG, through indirect subsidiaries, owns an effective 35% interest in the Indiantown partnership. Dana Commercial Corporation, through indirect subsidiaries, owns an effective 15% interest in the Indiantown partnership. One of our wholly-owned, indirect subsidiaries owns a direct 10% general partnership interest in the Indiantown partnership and a 40% limited partnership interest in the Indiantown partnership through another one of our wholly-owned indirect subsidiaries. The Indiantown facility began operation in December 1995 and sells steam to Louis Dreyfus Citrus, Inc.

          The Indiantown facility provides 330 megawatts of declared capacity to Florida Power & Light Company under a power sales agreement that expires in 2025. Capacity payments by Florida Power & Light are subject to adjustment on the basis of the Indiantown facility's actual production capability.

          Currently, Florida Power & Light is permitted full recovery from its customers of payments made under the power sales agreement. The power sales agreement contains a provision that provides if Florida Power & Light at any time is denied authorization to recover from its customers any payments to be made under the power sales agreement, Florida Power & Light may, in its sole discretion, adjust payments under the power sales agreement to the amount it is authorized to recover from its customers. The utility may also require the partnership that owns the facility to return payments subsequently disallowed by the regulatory agency. If the obligations of Florida Power & Light and the partnership that owns the facility are materially altered due to the operation of this provision in the agreement, the partnership may terminate the power sales agreement upon 60 days' notice. The partnership and Florida Power & Light must then, in good faith, attempt to negotiate a new power sales agreement or any agreement for transmission of the Indiantown facility's capacity and energy to another investor-owned, municipal, or cooperative electric utility interconnected with Florida Power & Light in Florida.

          An affiliate of NEG provides operation and maintenance services for the Indiantown facility pursuant to an operating agreement that expires in 2025. An affiliate of NEG manages and administers the business of the partnership that owns the facility pursuant to a management service agreement that expires in 2029. NEG has experienced a financial downturn, is currently in default on various recourse loan obligations, and is engaged in discussions on restructuring its loan and other agreements. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Events and Trends Affecting Our Financial Condition and Results of Operations - PG&E National Energy Group, Inc."

          The coal supplier and ash disposal vendor for Indiantown, Lodestar, filed for bankruptcy protection in April 2001. In 2001, Indiantown negotiated certain changes to the coal contract with Lodestar, which were approved by the bankruptcy court. Separately, in 2002 Lodestar's bankruptcy proceedings were modified so that its business and assets, including the Indiantown coal contract, will be sold. It is anticipated that Lodestar will not emerge from the bankruptcy as a going concern. Additionally, Lodestar has failed to perform certain of its obligations under the contract pertaining to ash disposal and Indiantown has delivered a notice of default to Lodestar. On March 20, 2003, Indiantown and Lodestar negotiated a settlement agreement under which Indiantown agreed to pay $1.0 million in exchange for the termination of the coal and ash disposal contract as of March 31, 2003 and the receipt of mutual releases of all outstanding issues. The terms of this settlement were submitted to the bankruptcy court on March 21, 2003, and barring any objections, approval should be received no later that April 4, 2003. When the contract is terminated as a result of this settlement, Indiantown has arranged for replacement coal supply and ash disposal services.

     Whitewater, Wisconsin Facility

          Our Whitewater facility is a 245-megawatt combined-cycle, natural gas-fired cogeneration facility in Whitewater, Wisconsin. One of our wholly-owned indirect subsidiaries is the sole general partner of the general partnership that owns the facility with a 1% general partnership interest. Another wholly-owned indirect subsidiary of ours owns an approximate 73.2% limited partnership interest. An affiliate of Arclight Capital Partners I, LLC owns the remaining approximate 25.8% limited partnership interest.

          The Whitewater facility provides approximately 236.5 megawatts of declared production capability to Wisconsin Electric Power Corporation under a power sales agreement that expires in 2022. The Whitewater facility may also sell to third parties up to 12 megawatts of electric production capability and any energy that the utility does not dispatch. Fixed payments from the utility are subject to adjustment on the basis of performance-based factors that reflect the Whitewater facility's semiannually tested production capability and average and on-peak availability for the preceding contract year.

          The fixed payments from the utility may be reduced to the extent that the utility's senior debt is downgraded by any two of Standard & Poor's Corporation, Moody's Investors Service, Inc. and Duff & Phelps as a result of the utility's long-term power purchase obligations under the power purchase agreement for the Whitewater facility. So long as the partnership's first mortgage bonds issued to finance construction of the facility are outstanding, the reduction may not exceed the level necessary to cause the partnership's debt service coverage ratio to be less than 1.4 in any one month, with such ratio calculated on a rolling average of the four fiscal quarters immediately preceding the proposed adjustment. After the partnership's first mortgage bonds have been repaid, the reduction may not exceed 50% of the partnership's revenues minus expenses. Reductions precluded by application of these limitations are accumulated in a tracking account with interest accruing at a specified rate. Tracking account balances are to be repaid when possible, subject to the limitations described above, or may be applied to the price of the utility's option to purchase the Whitewater facility at the expiration of the power sales agreement.

          Currently, Wisconsin Electric Power Company is permitted full recovery from its customers of payments made under the power sales agreement. The power sales agreement provides, however, if at any time the utility is denied rate recovery from its customers of any payment to be made under the power sales agreement by an applicable regulatory authority, the utility's payments may be correspondingly reduced, subject to contractually specified limitations. While the partnership's first mortgage bonds are outstanding, the fixed payments may be reduced by the annual regulatory disallowance provided that the reduction may not cause the partnership's debt service coverage ratio to be less than 1.4 in any month calculated on a rolling average of the four fiscal quarters preceding the proposed adjustment. After the outstanding first mortgage bonds are repaid, reductions may not exceed 50% of the Whitewater facility's revenues minus expenses. Reductions precluded by these restrictions are accumulated in a tracking account with repayment subject to the same provisions as for bond downgrading adjustments discussed above.

          The Whitewater facility sells steam to the University of Wisconsin - Whitewater under a steam supply agreement expiring in 2005. The facility also sells hot water to a greenhouse located adjacent to the facility. FloriCulture, Inc., an affiliate of the partnership that owns the Whitewater facility, has entered into an operational services agreement pursuant to which FloriCulture provides all services necessary to produce, market and sell horticulture products and to operate and maintain the greenhouse facility.

          We manage and administer the partnership's business with respect to the Whitewater facility, and provide management and administrative services to the general partner of the partnership. Also, one of our wholly-owned subsidiaries operates the facility pursuant to an operation and maintenance agreement with the partnership.

     Cottage Grove, Minnesota Facility

          Our Cottage Grove facility is a 245-megawatt combined-cycle, natural gas-fired cogeneration facility in Cottage Grove, Minnesota. One of our wholly-owned indirect subsidiaries is the sole general partner of the partnership that owns the facility with a 1% partnership interest. Another wholly-owned indirect subsidiary of ours owns an approximate 72.2% limited partnership interest in Cottage Grove. An affiliate of Arclight Capital Partners I, LLC owns the remaining approximate 26.8% limited partnership interest.

          The Cottage Grove facility provides 245 megawatts of declared production capability to Northern States Power Company ("Northern States Power") measured at summer conditions and 262 megawatts of declared production capability measured at winter conditions under a power sales agreement that expires in 2027. Fixed payments are subject to adjustment on the basis of performance-based factors that reflect the Cottage Grove facility's semiannually tested production capability and its rolling 12-month average and on-peak availability. Fixed payments are also adjusted for transmission losses or gains relative to a reference plant. The Cottage Grove facility, also sells steam to Minnesota Mining and Manufacturing Company.

          Currently, Northern States Power is permitted full recovery from its customers of payments made under the power sales agreement. The power sales agreement provides, however, that following the tenth anniversary of the commercial operation date, if Northern States Power fails to obtain or is denied authorization by any governmental authority having jurisdiction over its retail rates and charges, granting it the right to recover from its customers any payments made under the power sales agreement, the disallowed amounts will be monitored in a tracking account and the unpaid balance in the tracking account shall accrue interest. Within 30 days after the first mortgage bonds issued to finance the construction of the facility have been fully retired, Northern States Power may begin reducing payments to the partnership that owns the facility to ensure the payments are in line with Minnesota Public Utility Commission rates and begin amortizing the balance in the tracking account. Should Northern States Power exercise its right to reduce payments, the maximum reduction is 75% of the payment otherwise due for the period.

          We manage and administer the partnership's business with respect to the Cottage Grove facility, and provide certain management and administrative services to the general partner of the partnership. Also, one of our wholly-owned subsidiaries operates the facility pursuant to an operation and maintenance agreement with the partnership.

     Rathdrum, Idaho Facility

          Rathdrum Power owns a 270-megawatt combined-cycle, natural gas-fired electric generating facility located in Rathdrum, Idaho. One of our wholly-owned subsidiaries owns a 51% membership interest in Rathdrum Power and an affiliate of Avista Corporation owns the remaining 49% membership interest.

          Rathdrum Power provides Avista Turbine Power the entire facility production capacity under a power purchase agreement that expires in October 2026. Avista Turbine Power is required to provide natural gas to the facility and Rathdrum Power is required to convert the delivered fuel into electricity at a guaranteed efficiency. Rathdrum Power's operation above or below this guaranteed efficiency will result in payments from or to a tracking account. Avista Turbine Power has the exclusive right to dispatch the facility and is obligated to accept the entire net electric output of the facility. Avista Corporation, the parent company of Avista Turbine Power, has guaranteed Avista Turbine Power's payment obligations to Rathdrum Power.

          Rathdrum Power may provide Avista Turbine Power replacement power in the event the facility does not operate at the level dispatched by Avista Turbine Power. The facility will continue to receive fixed and variable payments from Avista Turbine Power while providing replacement power. In lieu of providing replacement power, the facility can accrue equivalent forced outage hours. If the cumulative equivalent forced outage hours exceed 263 hours during a rolling 12-month period, then, for the month following such 12-month period, the fixed payments are subject to reduction. Forced outage hours will not accrue as a result of scheduled maintenance, force majeure events, operation within 1.5% of Avista Turbine Power's dispatch and delivery excuses.

     Portsmouth, Virginia Facility

          Our facility located in Portsmouth, Virginia is a 120-megawatt stoker coal-fired cogeneration facility. The Portsmouth facility provides Dominion Virginia Power declared production capability of up to 115 megawatts under a power sales agreement that expires in June 2008. The power sales agreement for the Portsmouth facility provides for a significant reduction in fixed payments after December 2002. See "Management's Discussion and Analysis of Financial Condition and Results of Operation - Events and Trends Affecting Our Financial Condition and Results of Operations - Termination or Modification of Certain Power Sales Agreements at Some of Our Facilities." The Portsmouth facility also sells process steam to BASF Corporation and U.S. Amines (Portsmouth), LLC.

          If the power sales agreement for this facility is terminated prior to the end of its initial or any subsequent term, other than due to a default by Dominion Virginia Power, then our project subsidiary must pay a penalty to Dominion Virginia Power. The amount of the penalty is the difference between payments for production capability already made and those that would have been allowable under the applicable "avoided cost" schedules of Dominion Virginia Power, plus interest. Payments to our project subsidiary are not subject to reduction or refund due to a prohibition by the State Utility Commission of recovery from its customers by Dominion Virginia Power.

     Rocky Mount, North Carolina Facility

          Our facility located near Rocky Mount, North Carolina is a 120-megawatt stoker coal-fired cogeneration plant. Under a power sales agreement with North Carolina Power Company, a division of Dominion Virginia Power, the Rocky Mount facility provides declared production capability of 115.5 megawatts of electricity for an initial term expiring in October 2015. In addition, steam from the Rocky Mount facility is sold to Abbott Laboratories.

          The power sales agreement for this facility provides that in the event the state utility commission prohibits North Carolina Power from recovering from its customers payments made by North Carolina Power under the power sales agreement to our project subsidiary, our project subsidiary would recognize a reduction in payments received under the power sales agreement after the 18th anniversary of commencement of commercial operations of the facility to the extent necessary to repay North Carolina Power the amount disallowed by the utility commission with interest. In light of this provision in the power sales agreement, the project lender for the Rocky Mount facility has established a reserve account, which is required to be funded at any time a disallowance of payments occurs or, from and after January 1, 2004, any meritorious filing with the utility commission challenging the pass-through of payments made by the utility under the power sales agreement is made.

          If a disallowance event occurs during the period from 2003 through 2013, then 100% of the cash flow from the facility must be deposited to the reserve account until the balance of the reserve account is equal to the amount required to be funded. The amount required to be funded in such account is an amount equal to the lesser of:

          If the number of days in any year in which the Rocky Mount facility is unable to generate electricity in an amount equal to its declared production capability is more than the greater of 25 days or ten percent of the total number of days the facility was required by North Carolina Power to operate, then the fixed payments under the contract for that period will be reduced by four percent for each excess day. In the event capacity testing indicates that the Rocky Mount facility's dependable production capability is less than 90% of the declared production capability, our project subsidiary will be obligated to pay annual liquidated damages to North Carolina Power. A letter of credit has been posted by our project subsidiary in favor of North Carolina Power to secure its obligations to perform under the power sales agreement.

     Roxboro and Southport, North Carolina Facilities

          Our subsidiary, Cogentrix of North Carolina, Inc., operates stoker coal-fired cogeneration plants in both Roxboro and Southport, North Carolina, that are owned by another wholly-owned project subsidiary of Cogentrix Energy.

          Until December 2002, the Roxboro and Southport facilities sold electricity under separate power sales agreements to Carolina Power & Light ("CP&L"), doing business now as Progress Energy Carolinas. The 60-megawatt Roxboro facility operated at a declared production capability of up to 56 megawatts and the 120-megawatt Southport facility operated at a declared production capability of up to 107 megawatts.

          Since their power sales agreements expired, the Roxboro and Southport facilities have been operating under one-year contracts to sell energy and capacity to CP&L that expire in December 2003. These contracts provide for a significant reduction in capacity payments as compared to the contracts which expired in December 2002. The energy and capacity rates were set in accordance with CP&L's filed tariff rates for the purchase of energy and capacity from Qualifying Facilities ("QFs") as defined by the Federal Energy Regulatory Commission ("FERC"). These published tariff rates are approved by the North Carolina Utility Commission (the "NCUC") and represent CP&L's avoided cost as promulgated under FERC rules. Our entitlement to the capacity rate in the published tariff was contested by CP&L before the NCUC, which ruled in our favor in its order of March 7, 2003. CP&L filed a motion for reconsideration with the NCUC on March 21, 2003 which is pending.

          CP&L has made filings before the NCUC in the biennial avoided cost proceeding attempting to establish new rates, terms and conditions for the purchase of energy and capacity from QFs over five megawatts in size. If approved by the NCUC, these new terms and conditions may deter our project subsidiaries for these facilities from entering into future tariff-based contracts for the sale of energy and capacity with CP&L. Our project subsidiaries and other third parties are challenging this proposed tariff modification and believe that this new tariff would not comply with current FERC regulations. In addition, we are seeking the establishment of rates, terms and conditions which are in compliance with applicable state and federal laws and regulations. In the event that standard tariff contracts for energy and capacity are not available from CP&L, our project subsidiaries will make alternative arrangements for the electric output of the facilities. These arrangements may include sales contracts with other utilities or power marketers, or operation of the facilities as merchant plants.

          Collins & Aikman Corporation exercised its option to extend the steam contract through 2007 and continues to purchase process steam for its textile manufacturing facility from the Roxboro facility and ArcherDaniels-Midland Company also exercised its option to extend the steam contract until 2008 and continues to purchase steam for its pharmaceutical and chemical manufacturing company from the Southport facility.

     Birchwood, Virginia Facility

          Through an indirect, wholly-owned subsidiary we have a 50% interest in a partnership that owns a 240-megawatt pulverized coal-fired cogeneration facility in King George, Virginia. A subsidiary of Mirant Corporation owns the remaining 50% of the partnership. A 36-acre greenhouse located adjacent to the facility, which is jointly owned by us and a subsidiary of Mirant Corporation, uses steam from the facility. An affiliate of Mirant Corporation manages and operates the Birchwood facility.

          The Birchwood facility provides 218 megawatts of declared production capability to Dominion Virginia Power measured at summer conditions and 222 megawatts of declared production capability measured at winter conditions under a power sales agreement that expires in 2021. The power sales agreement provides that in the event the state utilities commission prohibits Dominion Virginia Power from recovering from its customers payments made by Dominion Virginia Power to our project affiliate, the partnership that owns the facility would recognize a reduction in payments received under the power sales agreement after the 20th anniversary of commencement of commercial operations of the facility to the extent necessary to repay the amount of the disallowed payments to Dominion Virginia Power with interest. During June 2000, the Birchwood facility signed a separate agreement with Dominion Virginia Power to sell up to 20 megawatts of supplemental capacity and energy, with an initial term expiring on December 31, 2003.

          If this facility is unable to operate within the parameters established by Dominion Virginia Power under the power sales agreement, the fixed payments under the agreement for the period the facility is not able to do so are subject to reduction. In the event testing indicates that the facility's dependable production capability is less than 90% of the declared production capability, the partnership will be obligated to pay annual liquidated damages to Dominion Virginia Power. The partnership has posted a letter of credit in favor of Dominion Virginia Power to secure its obligations to perform under the power sales agreement.

     Logan, New Jersey Facility

          A Delaware limited partnership owns the Logan facility, a 218-megawatt pulverized coal-fired, dual-certified QF and EWG cogeneration plant located on the Delaware River in Logan Township, New Jersey. The partnership leases the Logan facility to another Delaware limited partnership. Our indirect, wholly-owned subsidiary, owns a 50% general partnership interest in each of the first limited partnership and each of the partners of the second limited partnership. NEG is the sole limited partner in each of the first partnership and the partners of the second limited partnership, owning a 1% limited partnership interest. The NEG subsidiary also owns a 49% general partnership interest in each of the first partnership and each of the partners of the second limited partnership. The Logan facility sells steam to Ferro, formerly Monsanto\Solutia.

          The Logan facility provides up to 203 megawatts of declared production capability to Atlantic City Electric Company ("Atlantic") under a power sales agreement that expires in 2024. The Logan facility has the capability to provide up to approximately 15 megawatts of excess production capability and energy to third parties.

          If the net deliverable production capability of the Logan facility falls below 190,000 kilowatts, then the partnership that owns the facility must pay liquidated damages to the utility in an amount calculated using a formula that reflects both the amount of the deficiency and the rate those mid-Atlantic electric utilities who are members of a mid-Atlantic regional power pool and fail to satisfy their capacity obligations to the pool must pay to the other members to make up the deficiency.

          In 1999, Logan and Atlantic entered into arbitration regarding the testing procedure for facility heat rate as pertains to energy prices paid to Logan by Atlantic. The arbitration award issued in 2002 called for Logan to develop a new heat rate test procedure, and conduct new heat rate tests, the results of which would be used for current billing under the power sales agreement and applied retroactively to energy deliveries made since February 2000. The project expects to finalize new heat rates in accordance with the test procedure in 2003 and is not expected to have a material impact on our consolidated results of operations.

          An affiliate of NEG provides operation and maintenance services for the Logan facility pursuant to an operation and maintenance agreement with an initial term expiring in 2004. An affiliate of NEG provides management services pursuant to a management services agreement that expires in 2027. NEG has experienced a financial downturn, is currently in default on various recourse loan obligations, and is engaged in discussions on restructuring its loan and other agreements. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Events and Trends Affecting Our Financial Condition and Results of Operations - PG&E National Energy Group, Inc."

     Hopewell, Virginia Facility

          Our facility located in Hopewell, Virginia is a 120-megawatt stoker coal-fired cogeneration facility owned and operated by a general partnership, in which a 50% general partnership interest is owned by one of our subsidiaries. The remaining 50% partnership interest is owned by Capistrano Cogeneration Company, a subsidiary of NRG Energy, Inc.

          The Hopewell facility provides declared production capability of up to 92.5 megawatts to Dominion Virginia Power under a power sales agreement that expires in January 2008. This power sales agreement provides for a significant reduction in fixed payments after December 2002. See "Management's Discussion and Analysis of Financial Condition and Results of Operation - Events and Trends Affecting Our Financial Condition and Results of Operations - Termination or Modification of Certain Power Sales Agreements at Some of Our Facilities." If the power sales agreement is terminated prior to the end of its initial or any subsequent term other than due to a default by Dominion Virginia Power, the project partnership must pay a penalty to Dominion Virginia Power. The amount of the penalty is the difference between payments for production capability already made and those that would have been allowable under the applicable "avoided cost" schedules of the utility plus interest. Payments to the general partnership are not subject to reduction or refund due to a prohibition by the State Utility Commission of recovery from its customers by Dominion Virginia Power. Honeywell International, formerly known as Allied-Signal Corporation, purchases steam from the Hopewell facility.

Principal Customers

          Electric utility customers accounting for more than ten percent of our interest in the aggregate revenues of our project affiliates and project subsidiaries for the fiscal years ended December 31, 2002, 2001 and 2000 were as follows:

          As a result of recent growth and our projects currently under construction, our operations are now and will be even more diverse in the future with regard to both geography and fuel source and less dependent on any single project or customer. Our customers at the Southaven, Caledonia, Sterlington and Dominican Republic facilities which recently achieved commercial operations or are expected to achieve commercial operations during 2003 are currently in default of their power sales or conversion services agreements. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Cash flows from Our Project Subsidiaries and Project Affiliates - Caledonia and Southaven Facility Defaults, Sterlington Facility and Dominican Republic Facility."

Regulation

          Our facilities are subject to federal, state and local energy and environmental laws and regulations applicable to the development, ownership and operation of electric generating facilities. Federal laws and regulations govern transactions, rates, transmission access, and eligibility criteria for electric power plants. For certain facilities, state regulatory commissions may approve the rates and, in some instances, other terms under which utilities purchase electricity from independent producers. These state commissions may have broad jurisdiction, including siting jurisdiction, over non-utility owned power plants. Power plants also are subject to laws and regulations governing environmental emissions and other substances produced by a plant, along with the geographical location, zoning, land use and operation of a plant. Applicable federal environmental laws typically have state and local enforcement and implementation provisions. These environmental laws and regulations generally require that a wide variety of permits and other approvals be obtained before construction or operation of a power plant commences and that the power plant operates in compliance with them. We strive to comply with all environmental laws, regulations, permits and licenses but, despite such efforts, at times we have been in non-compliance, although not materially.

Energy Regulations

     Federal Regulation

          Overview.  Two federal statutes establish the basic statutory framework for ownership and operation of electric power plants-the Public Utility Holding Company Act of 1935 ("PUHCA") and the Federal Power Act ("FPA"). Two other federal statutes-the Public Utility Regulatory Policies Act of 1978 ("PURPA") and the Energy Policy Act of 1992 ("EPAct")-create certain regulatory exemptions for owners and operators of power plants and expand the authority of the "FERC" to order transmission access. In general, over time, implementation of these statutes has provided additional opportunities for independent power producers like Cogentrix Energy to compete in wholesale power markets. The discussion of the statutes set forth below focuses only on those provisions that affect our facilities.

          PUHCA regulates the structure of public utility "holding companies," which are generally defined by the statute as companies that own or control 10 percent or more of the voting securities of a "public-utility company." The definition of a public-utility company includes an "electric utility company", which, in turn, is defined as a company that owns or operates facilities used for the generation, transmission, or distribution of electric energy for sale. Any non-exempt public utility holding company under PUHCA is required to register with the Securities and Exchange Commission ("SEC"), to limit its operations to a single, geographically-confined integrated public utility system and such other businesses that are reasonably incidental to the operation of that system, and to submit to extensive financial and securities regulation by the SEC.

          The FPA grants FERC the exclusive authority to determine the rates, terms, and conditions of wholesale sales of electric energy in interstate commerce, and the transmission of electric energy in interstate commerce. This authority includes initial as well as ongoing rate jurisdiction, which enables FERC to modify or revoke previously approved rates. FERC's jurisdiction extends to any non-exempt owner or operator of facilities subject to the jurisdiction of FERC. FERC's jurisdiction also reaches power marketers that own no generation plant or transmission plant assets.

          PURPA was enacted in 1978 in an attempt by Congress to lessen dependence on oil and natural gas, to promote conservation, and to control the overall cost of generation. To meet these goals, PURPA grants to designated generating facilities - known as "qualifying facilities" or "QFs" - relief from most provisions of the FPA, PUHCA, and state law and regulation governing the rates of electric utilities and the financial and organizational regulation of electric utilities. Furthermore, PURPA requires utilities to purchase electricity generated by QFs at a price based on the purchasing utility's full "avoided cost," and to sell back-up power to QFs on a nondiscriminatory basis. To be a QF, a cogeneration facility must sequentially produce both electricity and useful thermal energy for non-mechanical or non-electrical uses in specified proportions to the facility's total useful energy output, and a cogeneration facility using oil or natural gas as fuel must meet energy efficiency standards. A small power production facility may be a QF if it uses alternative fuels as its primary energy input, subject to limitations on fossil fuel input and size for the facility. Finally, a QF may not be more than 50% owned or controlled by an electric utility or an electric utility holding company, or a subsidiary of either or combination thereof.

          EPAct implemented amendments to both PUHCA and the FPA that have facilitated the development of a competitive wholesale power market. EPAct establishes a new category of independent generators - "exempt wholesale generators" or "EWGs" - that are exempt from regulation under PUHCA. An EWG is any entity that is determined by FERC to be engaged directly, or indirectly through one or more affiliates, and exclusively in the business of owning and/or operating all or part of an eligible facility and selling electricity at wholesale. Although EWGs are exempt from regulation under PUHCA, they are still subject to regulation under the FPA and under state laws.

          EPAct also expanded the options for companies that wish to invest in foreign enterprises that own power production facilities outside the United States. Amendments to PUHCA in EPAct provide that a domestic company making such an investment may avoid regulation under PUHCA, if the foreign enterprise obtains EWG status or files a notice with the SEC that it is a foreign utility company ("FUCO").

          Finally, EPAct amended the FPA to expand FERC's authority to order jurisdictional utilities to provide open access transmission to third parties. Prior to the passage of EPAct, FERC had lacked the authority to require directly that jurisdictional utilities open their transmission lines to third parties. The EPAct amendments to the FPA enabled FERC to require, on a case-by-case basis, that jurisdictional utilities open their transmission lines to third parties. In April 1996, FERC issued a rulemaking order under the FPA, Order 888, requiring all jurisdictional public utilities to file "open access" transmission tariffs. Compliance with Order 888 has been virtually universal. FERC has also mandated that utilities with open access transmission tariffs provide interconnection service to generators as a separate component of transmission service. FERC is currently promoting the development of Regional Transmission Organizations. Such entities are designed to promote efficiencies in the provision of transmission service by better enforcing FERC's open access mandates, and eliminating the assessment of multiple rates to wheel power through a region.

          Impacts on Cogentrix Energy. All of our facilities qualify as QFs under PURPA or EWGs or FUCOs under EPAct, or in some cases, as both a QF and EWG. Therefore, all of our subsidiaries that own or operate power plants are exempt from regulation under PUHCA, except insofar as they may also be subsidiaries of registered holding companies. In addition, our power marketing subsidiary, which owns no electric facilities aside from books and records, is exempt from regulation under PUHCA. Our non-QF EWGs, as well as our power marketing subsidiary, are subject to rate regulation under the FPA. Finally, Cogentrix Energy and its subsidiaries may benefit from the increased transmission access to utility systems resulting from the FERC initiatives described above.


          For our current operating facilities classified as QFs under PURPA, we endeavor to minimize the risk of our facilities losing their QF status. The occurrence of events outside our control, such as loss of a steam customer, could jeopardize QF status. While the facilities usually would be able to react in a manner to avoid the loss of QF status by, for example, replacing the steam customer or finding another use for the steam that meets PURPA's requirements, there is no certainty that the alternative implemented would be practicable or economic.

          If one of our facilities were to lose its status as a QF, the subsidiary may lose its exemptions from PUHCA and the FPA and from state laws and regulations. This could subject the subsidiary to regulation under the FPA and may result in Cogentrix Energy inadvertently becoming subject to regulation under PUHCA. Our other facilities could in turn lose their QF status. Moreover, loss of QF status could result in utility customers terminating their power sales agreement with the non-qualifying facility. If loss of QF status were threatened for a facility, we could avoid holding company status under PUHCA and thereby protect the QF status of our other facilities by applying to the FERC to obtain EWG status for the owner of the non-qualifying facility. Alternatively, the FERC may grant a limited waiver to the QF that would provide continued exemption under PUHCA, provided the facility's rates were regulated under the FPA.

          Several of Cogentrix Energy's facilities that are QFs have also been determined to be EWGs. Some of these dually-certified facilities also have authority from FERC under the FPA to sell at market-based rates. In addition, our Southaven and Caledonia facilities, which are in the final stages of construction, will qualify as EWGs with market-based rate authority. ''

     State Regulation

          Public Utility Commissions ("PUCs") regulate retail rates of electric utilities. Thus, retail sales of electricity or steam by an independent power producer may be subject to PUC regulation, depending on state law. Due to the requirement that EWGs sell only at wholesale, only our QFs or our power marketer may be subject to such state regulation of retail sales. In addition, states have been delegated the authority to determine utilities' avoided cost under PURPA. PUCs often will pre-approve a purchasing utility's contract with a QF, where the contract price does not exceed avoided costs, because such contracts often have been acquired through a competitive or market-based process. Recognizing the competitive nature of the acquisition process, many PUCs permit utilities to recover from their ratepayers the costs of a power purchase agreement with an independent power producer.

          EWGs may be subject to broad regulation by PUCs, ranging from the requirement of certificates of public convenience and necessity to regulation of organizational, accounting, financial and other corporate matters. In addition, states may assert jurisdiction over the siting and construction of EWGs (as well as QFs) and over the issuance of securities and the sale or other transfer of assets by these facilities. Some state utility commissions and state legislatures are actively seeking ways to lower electric power costs at the retail level, including options that would permit or compel competition at the retail level. An opening of the retail market would create tremendous opportunities for companies that have until now been limited to the wholesale market. At the same time, state commissions are pressuring the utilities they regulate to cut purchased power costs through strict enforcement of existing contracts with QFs, many of which are considered to be overpriced in current market conditions. State commissions are also encouraging efforts by utilities to buy out or buy down such contracts.

     Proposed Legislation

          There are currently efforts in Congress to repeal PUHCA. Such efforts have been ongoing for years, and although there had been some momentum for the passage of PUHCA repeal, the collapse of Enron Corporation has slowed that momentum considerably. Elimination of PUHCA would enable more companies to consider owning generating, transmission and distribution assets, would permit "single state" utility systems to expand beyond their state borders, and would permit companies that are currently in registered holding company systems to diversify their investments to a greater extent than now permitted. This could attract more competitors to the power development and power marketing business. We believe that we are well positioned, however, to meet stronger competition and, indeed, may be able to pursue more investment opportunities made available by the potential repeal of PUHCA.

         Although such initiatives are slowing, the state commissions or state legislatures of some states are considering, or have considered, whether to open the retail electric power market to competition. These initiatives are generally called "retail access" or "customer choice". Such "customer choice" plans typically allow customers to choose their electricity suppliers by a certain date. Retail competition is possible when a customer's local utility agrees, or is required, to "unbundle" its distribution service, that is, the delivery of electric power to retail customers through its local distribution lines, from its transmission and generating service.

          The competitive price environment that would result from retail competition may cause utilities to experience revenue shortfalls and deteriorating creditworthiness. However, most, if not all, state plans will insure that utilities receive sufficient revenues, through a distribution surcharge if necessary, to pay their obligations under existing long-term power purchase contracts with QFs and EWGs, including the above market rates, or "stranded investment" costs, provided for in such contracts. Many states will also provide that the stranded investment costs will be "securitized" through new financial instruments. On the other hand, QFs and EWGs may be subject to pressure to lower their contract prices or to renegotiate contracts in an effort to reduce the "stranded investment" costs of their utility customers.

     Environmental Regulations - United States

          The following discussion includes forward-looking statements relating to environmental protection compliance measures and the possible future impact on us of increasingly stringent environmental regulations. This information reflects current estimates that we periodically evaluate and revise. Our estimates are subject to a number of assumptions and uncertainties, including future Federal and state energy and environmental policy, other changing laws and regulations, the ultimate outcome of complex factual investigations, changes in emission control technology, and selection of compliance alternatives.

          The construction and operation of power projects are subject to extensive environmental protection and land use regulation in the United States. Those regulations applicable to Cogentrix primarily involve the discharge of emissions into the water and air and the use of water, but can also include wetlands preservation, endangered species, waste disposal and noise regulation. These laws and regulations often require a lengthy and complex process of obtaining and renewing licenses, permits and approvals from federal, state and local agencies. If such laws and regulations are changed and our facilities are not grandfathered, extensive modifications to power project technologies and facilities could be required.

          We expect that environmental regulations will continue to become more stringent as environmental legislation previously passed is implemented, new laws are enacted and existing regulations are re-evaluated. Accordingly, we plan to continue a strong emphasis on implementation of environmental controls and procedures to minimize the environmental impact of energy generation at our facilities.

          Clean Air Act and the 1990 Amendments.  In late 1990, Congress passed the Clean Air Act Amendments of 1990 (the "1990 Amendments") that affect existing facilities - including facilities exempt from regulation under the Clean Air Act of 1970 - as well as new project development. All of the facilities we operate are currently in compliance with federal performance standards mandated for such facilities under the Clean Air Act and the 1990 Amendments.

          The 1990 Amendments create a marketable commodity called a sulfur dioxide ("SO₂") "allowance." All non-exempt facilities over 25 megawatts that emit SO₂ including independent power plants, must obtain allowances in order to operate after 2000. Each allowance gives the owner the right to emit one ton of SO₂. The 1990 Amendments exempt from the SO₂ allowance provisions all independent power projects that were operating, under construction or with power sales agreements or letters of intent as of November 15, 1990, as well as facilities outside the contiguous 48 states. As a result, most of the facilities we operate are exempt. The non-exempt facilities we operate have determined their need for allowances and have accounted for these requirements in their operating budgets and financial forecasts. Most of the facilities we have developed in recent years and expect to develop in the future rely on natural gas technology, which does not give rise to the need for significant amounts of these allowances. The additional costs of obtaining the number of allowances needed for our future projects should not materially affect our ability to develop new projects.

          The 1990 Amendments also contain other provisions that could affect our projects. Provisions dealing with geographical areas the EPA has designated as being in "nonattainment" with national ambient air quality standards require that each new or expanded source of air pollutants in nonattainment areas must obtain emissions reductions from existing sources that more than offset the emissions from the new or expanded source. While the "offset" requirements may hamper new project development in certain geographical areas, development of new projects has continued, and management expects will likely continue, particularly as markets for "offsets" develop.

          The 1990 Amendments also provide an extensive new operating permit program for existing sources called the Title V permitting program. Because all of the facilities we operate were permitted under the Prevention of Significant Deterioration New Source Review Process, the permitting impact to Cogentrix under the 1990 Amendments at those facilities is expected to be minimal. The costs of applying for and maintaining operating air permits are not anticipated to be significant. Title V operating permits have been received for all currently operating plants with the exception of Rathdrum and Green Country, which have applications pending.

          The 1990 Amendments also regulate certain hazardous air pollutant ("HAP") emissions. Although the HAP provisions of the 1990 Amendments exclude electric steam generating facilities, they direct the EPA to prepare a study on HAP emissions from power plants. The EPA has conducted agreed studies and is expected to regulate mercury emissions, and possibly other types of emissions, from power plants on or before December 15, 2004. If it is determined that these emissions from power plants should be regulated, the use of "maximum achievable control technology" could be required, which could require additional control equipment on some or all of our facilities.

          The EPA has recently proposed to control HAP emissions from industrial boilers and process heaters. Since several facilities have boilers that generate below 25 Mw - the level that may trigger the applicability of the electric steam generating rule - it is possible that these units could be subject to this rule. If these units are determined to be subject to this rule, controls on particulate matter and hydrogen chloride may be required to meet the proposed "maximum applicable control technology" ("MACT") standard for this category. This regulation is proposed and the final regulation may or may not be more or less stringent than that proposed.

          The EPA also has recently proposed to control HAP emissions from stationary combustion turbines. Several facilities have combustion turbines that are subject to this regulation. However, all of our combustion turbines are of the type and are operated such that the proposed regulation will require only more reporting requirements and not additional control technology. This regulation is proposed and the final regulation may be more or less stringent than that proposed.

          The EPA continues to conduct an industry-wide investigation of coal-fired electric power generators to determine compliance with environmental requirements under the Clean Air Act associated with repairs, maintenance, modifications and operational changes made to the facilities over the years. The EPA's focus is on whether any of the changes made were subject to new source review or new performance standards, and whether best available control technology was or should have been used. Cogentrix has not received any notices of violation from the EPA relating to any of its facilities as a result of this industry-wide investigation. The Portsmouth Plant has received and responded to a Section 114 Request from EPA Region III to "provide information reasonably required for the purpose of determining whether that person is in violation of, among other things, any requirements of the State Implementation Plan ("SIP"), New Source Performance Standards and Review of New Sources and modifications." The EPA conducted its site visit to the Portsmouth Plant on March 7, 2001. In addition, the Richmond facility received a notice of inspection from the EPA regarding this facility's compliance with certain aspects of the Clean Air Act. The EPA conducted its site visit to the Richmond Plant on April 23, 2002. EPA has taken no action as a result of these inspections and no actions are expected at this time. Management believes that Cogentrix would have a meritorious defense to any action brought by the EPA relating to any of its facilities.

          EPA Initiatives.  In July 1997, the EPA promulgated more restrictive ambient air quality standards for ozone and for particulate matter. These new standards were affirmed by the Supreme Court in February 2001 and when finally promulgated by the EPA will likely increase the number of nonattainment areas for both ozone and particulate matter. If our facilities are in these new nonattainment areas, further emission reduction requirements, which states will be required to adopt, could require us to install additional control technology for oxides of nitrogen ("NO_x") emissions, other ozone precursors and particulate matter.

          In October 1998, the EPA issued a final rule addressing the regional transport of ground-level ozone across state boundaries to the eastern United States through NO_x emissions reduction. The rule focuses on such reductions in the eastern United States, requiring 22 states and the District of Columbia to submit revised SIPs by September 1999 and have NO_x emission controls in place by May 2003 (the " NO_x SIP call"). In March 2000, a federal appeals court upheld the NO_x SIP call rule. In March 2001, the Supreme Court declined to hear an appeal of this ruling.

          In a related action, the EPA in December 1999 granted petitions of four northeastern states seeking to reduce transport of ozone across state boundaries by requiring reductions in NO_x emissions from sources in 30 states and the District of Columbia. As a result, 392 facilities, including those operated by our project subsidiaries in North Carolina and Virginia, will have to reduce NO_x emissions or take other steps to meet these NO_x emission reduction requirements. Under these petitions, facilities would have to implement controls or use emission allowances to achieve required NO_x emission reductions by May 2003.

          A January 2002 EPA memorandum discusses the EPA's intent to harmonize the compliance dates for the NO_x SIP Call and the Section 126 Rule. It is EPA's intent to establish May 31, 2004 as the compliance date for all affected sources, subject to the completion of EPA's response to the related court decision. As a result, the compliance date has been delayed until the 2004 ozone season and there is an expected date certain.

          We are evaluating the NO_x emission reductions that these EPA initiatives and state regulations will require us to meet. Upgrade of continuous emissions monitoring equipment has already been completed to meet the May 2003 deadline for this upgrade. We expect we will need to install and are in the process of installing additional or new control equipment at several of the facilities operated by our project subsidiaries in North Carolina and Virginia. The costs of the additional equipment should not be material to the operations of these facilities. In addition to installing new control equipment, we will need to purchase NO_x "allowances".

          The 1990 Amendments expand the enforcement authority of the federal government by increasing the range of civil and criminal penalties for violations of the Clean Air Act, enhancing administrative civil penalties, and adding a citizen suit provision. These enforcement provisions also include enhanced monitoring, recordkeeping and reporting requirements for existing and new facilities. On February 13, 1997, the EPA issued a regulation providing for the use of "any credible evidence or information" in lieu of, or in addition to, the test methods prescribed by regulation to determine the compliance status of permitted sources of air pollution. This rule may effectively make emission limits previously established for many air pollution sources, including the facilities, more stringent.

          The Bush Administration is developing, and several members of Congress have introduced, multi-pollutant emission reduction legislation aimed at power plants. This new legislation would be designed to replace existing permitting programs and impose new emission limits and related requirements on power plants for NO_x , SO₂, mercury and, potentially, carbon dioxide. We cannot determine whether this new multi-pollutant approach to regulating power plants will become law and, if so, its effect on future emissions reduction requirements on Cogentrix facilities.

          The Kyoto Protocol.  In 1998, the Kyoto Protocol regarding greenhouse gas emissions and global warming was signed by the U.S., committing to reductions in greenhouse gas emissions of at least 7% below 1990 levels to be achieved by 2008 - 2012. The U.S. Senate must ratify the agreement for the protocol to take effect. In March 2001, the EPA announced that the United States would not be implementing the Kyoto Protocol in its present form. In February 2002, the Bush Administration announced a series of voluntary measures aimed at reducing the amount of greenhouse gas emissions. The effects on Cogentrix from these initiatives are unknown at this time.

          Clean Water Act.  Our facilities are subject to a variety of state and federal regulations governing existing and potential water/wastewater and stormwater discharges from the facilities. Generally, federal regulations promulgated through the Clean Water Act govern overall water/wastewater and stormwater discharges through National Pollutant Discharge Elimination System permits. Under current provisions of the Clean Water Act, existing permits must be renewed every five years, at which time permit limits are under extensive review and can be modified to account for more stringent regulations. In addition, the permits have re-opener clauses that can be used to modify a permit at anytime, and the states are required to establish total maximum daily load limits for water bodies that are impaired. Several of the facilities we operate have either recently gone through permit renewal or will be renewed within the next few years. Based upon recent renewals, we do not anticipate significantly more stringent monitoring or treatment requirements for any of the facilities we operate. We believe that the plants we operate are in material compliance with applicable discharge requirements under the Clean Water Act.

          The EPA is currently developing new regulatory requirements under the NPDES permit program for new and existing facilities that employ a cooling water intake structure. None of the Cogentrix facilities are directly affected by this new EPA initiative.

          Emergency Planning and Community Right-to-Know Act.  In April of 1997, the EPA expanded the list of industry groups required to report the Toxic Release Inventory under Section 313 of the Emergency Planning and Community Right-to-Know Act to include electric utilities. Our operating facilities are required to complete a toxic chemical inventory release form for each listed toxic chemical manufactured, processed or otherwise used in excess of threshold levels. The purpose of this requirement is to inform the EPA, states, localities and the public about releases of toxic chemicals to the air, water and land that can pose a threat to the community. We have complied with this reporting requirement.

          Comprehensive Environmental Response, Compensation, and Liability Act.  The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended ("CERCLA" or "Superfund"), requires cleanup of sites from which there has been a release or threatened release of hazardous substances and authorized the EPA to take any necessary response action at Superfund sites, including ordering potentially responsible parties ("PRPs") liable for the release to take action or pay for such actions by others. PRPs are broadly defined under CERCLA to include past and present owners and operators of sites, as well as generators of wastes sent to a site. At present, we are not subject to liability for any Superfund matters and take measures to assure that CERCLA will not apply to properties we own or lease. However, we do generate certain wastes in the operation of our plants, including small amounts of hazardous wastes, and send certain wastes to third-party waste disposal sites. As a result, there can be no assurance that we will not incur liability under CERCLA in the future.

          Resource Conservation and Recovery Act ("RCRA").  RCRA regulates the generation, treatment, storage, handling, transportation and disposal of hazardous wastes. We are exempt from the solid waste requirements under RCRA regarding coal combustion by-products. We are classified as a small quantity generator or a conditionally exempt small quantity generator of hazardous wastes at all of our facilities with most of the plants being conditionally exempt. We will continue to monitor regulations under this rule and will strive to maintain the exempt status.

     Environmental Regulations - International

          Although the type of environmental laws and regulations applicable to independent power producers and developers varies widely from country to country, many foreign countries have laws and regulations relating to the protection of the environment and land use that are similar to those found in the United States. Laws applicable to the construction and operation of electric generating facilities in foreign countries generally regulate discharges and emissions into water and air and also regulate noise levels.

          Air pollution laws in foreign jurisdictions often limit the emissions of particulates, dust, smoke, carbon monoxide, sulfur dioxide, nitrogen oxide and other pollutants. Water pollution laws in foreign countries generally limit wastewater discharges into municipal sewer systems and require treatment of wastewater that does not meet established standards. New projects and modifications to existing projects are also subject, in many cases, to land use and zoning restrictions imposed in the foreign country. In addition, developers of foreign independent power projects often conduct environmental impact assessments of proposed projects pursuant to existing legislative requirements. Lenders to international development projects may impose their own requirements relating to the protection of the environment.

          We believe that the level of environmental awareness and enforcement is growing in most countries, including most of the countries in which we intend to develop and operate new projects. As a result, plants built overseas will likely include pollution control equipment that is required in the United States. Therefore, based on current trends, we believe that the nature and level of environmental regulation that we are subject to will become increasingly stringent, whether we undertake new projects in foreign countries or in the United States.

Employees

          At December 31, 2002, we employed 533 people, none of whom is covered by a collective bargaining agreement.

Item 2. Properties

          In addition to our properties listed and described in the section entitled "Business - Facilities in Operation," we own our principal executive office, a single 61,024 square foot building, located at 9405 Arrowpoint Boulevard in Charlotte, North Carolina.

          We also lease office space in Prince George, Virginia, Wilmington, Delaware and two warehouse facilities in Prince George, Virginia.

          We believe that our facilities and properties have been satisfactorily maintained, are in good condition, and are suitable for our operations.

Item 3. Legal Proceedings

     Product Liability Claims Related to Coal Combustion By-Products

          One of our indirect, wholly-owned subsidiaries is party to certain product liability claims related to the sale by that subsidiary of coal combustion by-products for use in 1997 and 1998 in various construction projects. We cannot currently estimate the range of possible loss, if any, we will ultimately bear as a result of these claims. However, we believe - based on our knowledge of the facts and legal theories applicable to these claims, after consultations with various counsel retained to represent the subsidiary in the defense of such claims, and considering all claims resolved to date - that the ultimate resolution of these claims should not have a material adverse effect on our consolidated financial position or results of operations.

     Claims Asserted by City of Jenks against our Jenks, Oklahoma Facility

          In October 2002, the City of Jenks, Oklahoma filed a petition in the District Court for Tulsa County, State of Oklahoma against our indirect, wholly-owned subsidiary, Green Country Energy, LLC ("Green Country"), which owns our Jenks facility. The petition also names as defendants the counterparty under the conversion services agreement for this facility, Exelon Generation Company, LLC ("Exelon"), and a third party that transports natural gas on behalf of Exelon. The City of Jenks claims that Green Country is liable for failure to pay an annual gross receipts tax of 2% on sales of electricity and that Green Country and the other defendants are also liable to Jenks for failure to pay a pipeline capacity permit fee of 3% of the purchase price of natural gas transported to the Green Country facility. Our project subsidiary's position is that it does not "sell" electricity to Exelon, and, even if the conversion services agreement is construed as a "sale" of electricity, the sale is wholesale in interstate commerce and not a sale to a residential or commercial user. In regard to the pipeline capacity permit fee, the defendants have asserted that the pipelines are not located within the city's rights of way and, therefore, are not subject to the fee. If it were to be determined that the pipeline capacity permit fee is applicable, the calculation of the amount due to the City of Jenks would be problematic as the calculation is based upon the purchase price of gas, and Green Country does not purchase gas from Exelon. We believe that our project subsidiary has meritorious defenses to these claims and intends to contest them vigorously.

          Letter of Credit Draw Litigation - Jenks, Oklahoma Facility

          To support the obligations of National Energy Production Company ("NEPCO"), the contractor initially engaged to construct our Jenks facility, Bayerische Hypo-und Vereinsbank AG ("HVB") issued a $39.0 million letter of credit for our benefit related to the construction of the Jenks facility. During February 2001, HVB sold and transferred, without recourse, an undivided 100% interest in this letter of credit to Banca Nagionale del Larvaro SPA ("BNL") under a participation agreement executed by HVB and BNL. Our project subsidiary drew this $39.0 million letter of credit in December 2001, after NEPCO failed to meet certain obligations under the construction contract. When HBV requested reimbursement for the amount drawn from BNL pursuant to the participation agreement, BNL refused to pay. In response, HBV filed an action in the Supreme Court of the State of New York in December 2001, against BNL for reimbursement of the $39.0 million plus costs and attorneys fees for breach of the participation agreement. In February 2002, BNL filed a third-party complaint against Green Country, Cogentrix Energy, NEPCO and Green Country's administrative agent for its outstanding indebtedness seeking recovery from each of them of the $39.0 million, plus interest, attorneys' fees and other unspecified damages. The case was removed to the United States Bankruptcy Court, Southern District of New York, in July 2002. We believe that Cogentrix Energy and Green Country each have meritorious defenses to these claims and intend to contest them vigorously.

          During December 2002, JP Morgan Chase Bank ("JP Morgan") commenced a separate action in the United States District Court, Southern District of New York against Cogentrix Energy, Green Country and Cogentrix of Oklahoma, Inc. arising out of a $14.0 million draw Green Country made in December 2001 on a letter of credit that JP Morgan issued on behalf of NEPCO. This letter of credit was also issued to support certain obligations of NEPCO related to the construction of the Jenks facility. The complaint alleges that the draw was wrongful because the construction of the Jenks facility was completed substantially on time and the draw was a breach of the original NEPCO contract because it did not meet the conditions to draw these funds. The case was referred to the United States Bankruptcy Court, Southern District of New York, in March 2003. We believe that Cogentrix Energy, Green Country and Cogentrix of Oklahoma, Inc. each have meritorious defenses to these claims and intend to contest them vigorously.

     Letter of Credit Draw Litigation - Sterlington Facility

          During December 2002, JP Morgan commenced an action in the United States District Court, Southern District of New York against Cogentrix Energy, Quachita Power, LLC ("Quachita"), which owns our Sterlington facility, and Cogentrix Ouachita Holdings, Inc. arising out of a $41.2 million draw in May 2002 on a letter of credit that JP Morgan issued to support certain obligations of NEPCO related to the construction of the Sterlington facility. The complaint alleges that the construction of the Sterlington facility was deliberately delayed by Quachita in order to draw on the letter of credit and that the draw was a breach of the original NEPCO contract because the conditions had not been met to draw these funds. The case was referred to the United States Bankruptcy Court, Southern District of New York, in March 2003. We believe that Cogentrix Energy, Quachita and Cogentrix Ouachita Holdings, Inc. all have meritorious defenses to these claims and intend to contest them vigorously.

          During February 2003, Westdeutsche Landesbank Girozentrale ("WestLB") commenced an action in the United States District Court, Southern District of New York against Quachita arising out of Quachita's draw in May 2002 on a $16.2 million letter of credit that WestLB issued to support certain obligations of NEPCO related to the construction of the Sterlington facility. The complaint alleges that the draw was improper and that the contractual conditions allowing this draw to be made had not been met. We believe that Quachita has meritorious defenses to WestLB's claims and intend to contest them vigorously.

     Other Routine Litigation

          In addition to the litigation described above, we experience other routine litigation in the normal course of business. We do not believe that any of this routine litigation, if decided adversely to us, would have a material adverse impact on our consolidated financial position or results of operations.

Item 4. Submission of Matters to a Vote of Security Holders

          None.

Item 6. Selected Consolidated Financial Data

          The following table sets forth certain selected consolidated financial data as of and for the five years ended December 31, 2002, which should be read in conjunction with our consolidated financial statements and related notes thereto and with "Management's Discussion and Analysis of Financial Condition and Results of Operations." The selected consolidated financial data as of and for each of the five years in the period ended December 31, 2002 set forth below has been derived from our audited consolidated financial statements.

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

          In addition to discussing and analyzing our recent historical financial results and condition, the following discussion includes statements concerning certain trends and other forward-looking information affecting or relating to Cogentrix that are intended to qualify for the protections afforded "Forward-Looking Statements" under the Private Securities Litigation Reform Act of 1995, Public Law 104-67. The forward-looking statements made herein and elsewhere in this Form 10-K are inherently subject to risks and uncertainties that could cause the actual results to differ materially from the forward-looking statements. See cautionary statements appearing in the Business section above and elsewhere in this Form 10-K for a discussion of the important factors affecting the realization of those results.

Trends Affecting the Electric Generating Industry

          During 2002, the electric power generation industry experienced a number of adverse trends that will limit our ability to develop or acquire electric generating facilities. These trends included:

          As discussed in NEG's recent filings with the SEC, NEG has experienced a financial downturn over the past year that caused the major credit rating agencies to downgrade NEG and its subsidiaries' credit ratings below investment grade. NEG is currently in default on various recourse debt agreements and guaranteed equity contracts and is currently engaged in discussions regarding the restructuring of these commitments. If a restructuring agreement is not reached or if the financial commitments are not restructured, NEG and certain of its subsidiaries may be compelled to seek protection under or be forced involuntarily into a proceeding under the U.S. Bankruptcy Code. If the NEG Affiliate that provides maintenance and operating services to our Logan facility is brought into bankruptcy proceedings with NEG, it would create an event of default under the Logan facility's non-recourse project loan agreements. This event of default would create a cross-default under our subsidiary Eastern America's credit facility that would give the lenders the right to exercise all remedies available to them including foreclosing upon and taking possession of the capital stock of Eastern America. If the NEG Affiliates who are the purchasers under the conversion services agreements for our Southaven and Caledonia facilities are brought into bankruptcy proceedings with NEG, significant doubt would occur as to their ability or continued willingness to perform under these conversion services agreements and additional events of default would occur under these project subsidiaries' non-recourse project loan agreements. The applicable project lenders would, therefore, not be obligated to continue funding construction draws and have the right to exercise all remedies available to them under the applicable project loan agreements, including foreclosing upon and taking possession of all of the applicable project assets.

Results of Operations

Year Ended December 31, 2002 as compared to Year Ended December 31, 2001

     Operating Revenues and Income from Unconsolidated Investment in Power Projects

          Total operating revenues and income from unconsolidated investment in power projects increased 13.2% to $642.9 million for the year ended December 31, 2002 as compared to $568.1 million for the year ended December 31, 2001 as a result of the following:

     Operating Expenses

          Total operating expenses increased 20.2% to $303.8 million for the year ended December 31, 2002 as compared to $252.8 million for the year ended December 31, 2001 as a result of the following:

     General, Administrative and Development Expenses

          General, administrative and development expenses remained stable for the year ended December 31, 2002 as compared to the year ended December 31, 2001 as a result of the following:

Year Ended December 31, 2001 as compared to Year Ended December 31, 2000

     Operating Revenues and Income from Unconsolidated Investment in Power Projects

          Total operating revenues and income from unconsolidated investment in power projects increased 3.1% to $568.1 million for the year ended December 31, 2001 as compared to $551.1 million for the year ended December 31, 2000 as a result of the following:

     Operating Costs

          Total operating expenses decreased 2.1% to $252.8 million for the year ended December 31, 2001 as compared to $258.2 million for the year ended December 31, 2000. This decrease was primarily the result of the cost of services which decreased $10.2 million as a result of a decrease in megawatt hours sold to the purchasing utilities at our Cottage Grove and Whitewater facilities. This decrease was partially offset by an increase in the average natural gas prices during 2001 compared to 2000.

     General, Administrative and Development Expenses

          General, administrative and development expenses increased 47.0% to $62.2 million for the year ended December 31, 2001 as compared to $42.3 million for the year ended December 31, 2000. This increase is primarily due to an increase in costs incurred in the pursuit of developing new electric generating facilities and an increase in consulting costs. In addition, we realized an increase in incentive compensation expense related to our increased profitability and the attainment of certain performance targets and an increase in compensation expense related to an increase in the number of corporate employees.

     Depreciation and Amortization

          Depreciation and amortization decreased 18.5% to $41.3 million for the year ended December 31, 2001, as compared to $50.7 million for the year ended December 31, 2000. This decrease was primarily a result of the sale of three of our facilities during the first quarter of 2001. This decrease was partially offset by the commencement of commercial operations of two new facilities during the second half of 2001.

     Interest Expense

          Interest expense decreased 7.5% to $97.3 million for the year ended December 31, 2001 as compared to $105.2 million for the year ended December 31, 2000. The decrease in interest expense is primarily related to lower interest rates on our variable rate borrowings and scheduled repayments and early retirements of project subsidiary financing debt. The decrease in interest expense was partially offset by the issuance of an additional $100.0 million in September 2000 of 8.75% senior notes due 2008 and the inclusion of interest on project financing debt of the two facilities which commenced commercial operations during the second half of 2001.

Liquidity and Capital Resources

     Consolidated Information

          The primary components of cash flows from operations for the year ended December 31, 2002, were as follows (dollars in millions):

          Total cash flows from operations of $85.8 million, proceeds from borrowings of $600.1 million, additional investments from minority interests of $3.8 million and funds released from escrow of $34.5 million and cash on hand at the beginning of the year of $170.7 million were used primarily to (dollars in millions):

     Parent Company Liquidity

          As of December 31, 2002, we had long-term debt (including the current portion thereof) of approximately $2.6 billion. With the exception of the $400.6 million of senior notes outstanding as of December 31, 2002, and $93.8 million in advances under the corporate credit facility, substantially all such indebtedness is project financing debt, the majority of which is non-recourse to Cogentrix Energy. Accordingly, we believe that the unconsolidated parent company liquidity position is more important than the liquidity position of the Company and its consolidated subsidiaries as presented on a consolidated basis. As of December 31, 2002, the Parent company, Cogentrix Energy, had approximately $20.8 million of unrestricted cash and Cogentrix Delaware Holdings, Inc., a wholly-owned subsidiary of Cogentrix Energy and guarantor of all of Cogentrix Energy's senior, unsecured debt, had no unrestricted cash. The parent company's principal sources of liquidity are:

The parent company's principal uses of cash are:

As of the date of this filing, the Parent company's non-contingent contractual obligations are set forth below (dollars in millions):

As of the date of this filing, the Parent company's contingent contractual obligations are set forth below (in millions, except for number of agreements):

(a)      Secured by letters of credit issued under our corporate credit facility

          Our contingent contractual obligations are designed to cover potential risks and only require payment if certain targets are not met or certain contingencies occur. The risks associated with these contingent obligations include construction cost overruns, unpaid construction liquidated damages owed by NEPCO at our Southaven facility and guarantees supporting our project subsidiaries' obligations under certain conversion service agreements. Aside from the $4.0 million in anticipated 2003 supplemental equity commitments for anticipated cost overruns at the Southaven facility, we do not expect these letters of credit will be drawn upon to fund any material amounts under these contingent contractual obligations during 2003, many of the events that would result in a draw upon these letters of credit are beyond our control.

          Our management believes that cash on hand and expected 2003 cash flows from our project subsidiaries and project affiliates will be adequate to meet our non-contingent contractual obligations in the table above and our other 2003 operating obligations, including interest and fees related to the corporate credit facility and recurring general and administrative costs. However, this belief is based on a number of material assumptions, including, without limitation, the continuing ability of our project subsidiaries and project affiliates to pay dividends, management fees and other distributions and our ability to refinance our corporate credit facility before maturity. Additional liquidity could be provided through the sale of selected project assets. We cannot assure you that these sources of cash will be available when needed or that our actual cash requirements will not be greater than we anticipate.

     Corporate Credit Facility

          We have an unsecured $250 million corporate credit facility that provides for either direct borrowings or the issuance of letters of credit for our benefit to third parties that, if they become entitled to and do draw upon them, will convert into borrowings under this credit facility. At present, there are $126.8 million of borrowings and $120.7 million of letters of credit outstanding representing a total use of the commitment of $247.5 million. We posted the letters of credit primarily to secure commitments - both non-contingent and contingent - we have made to support our project subsidiary that is constructing the Southaven facility.

          The corporate credit facility matures in October 2003 at which time all outstanding obligations will become due and payable. We are currently negotiating to obtain a commitment letter for a restructured facility and have engaged two of our existing lenders to lead the restructuring process. Deteriorating market conditions for borrowers in the energy industry and concerns about the uncertainties we face and our liquidity are likely to result in higher interest costs, reduced borrowing capacity and more restrictive terms and conditions in any restructured credit facility than we have in our current credit facility. Although we believe we will be successful, we cannot assure you that we will be able to restructure the credit facility and refinance the outstanding obligations prior to the facility's maturity date in October 2003 due to these uncertainties.

          As a result of the maturity of $247.5 million in obligations outstanding under our corporate credit facility in October 2003, our independent auditors expressed a going concern uncertainty in their report on our consolidated financial statements for the year ended December 31, 2002 that triggered an event of default under our corporate credit facility. Until we cure this event of default, we will not be able to borrow any of the $2.5 million balance of commitments available or post any additional letters of credit under the credit facility. We also will not be able to make any restricted payments, a category that includes shareholder dividends and loans, or repay any of our other senior indebtedness prior to its scheduled maturity. Since this event of default occurred, the lenders have provided us with a limited waiver through May 31, 2003 that will allow us to continue to convert to borrowings, drawings under outstanding letters of credit issued to support our Southaven Project. Even though they have granted this limited waiver, we cannot assure you that the lenders to the corporate credit facility will not choose nonetheless at any time to accelerate the obligations outstanding under the corporate credit facility and demand immediate payment of all obligations outstanding. In the event the lenders to the corporate credit facility accelerate the outstanding obligations, or if the corporate credit facility matures and is not repaid, this would create a cross-default under the indentures under which we issued our senior notes, and the senior note holders would have the ability to accelerate the $394.7 million of senior notes currently outstanding and demand immediate payment.

     Facilities Under Construction

          We currently have two electric generating facilities, Southaven and Caledonia, under construction, both of which we expect to complete by mid-2003. The construction of each facility was or is being funded under each project subsidiary's separate financing agreements and our equity contribution commitments. Our remaining Southaven equity commitments are supported by letters of credit issued under our corporate credit facility and are expected to be contributed utilizing corporate cash balances or converting the outstanding letters of credit to borrowings under the corporate credit facility. Summarized information regarding each of the facilities follows (dollars in millions):

          During 2002, our Dominican Republic, Jenks and Sterlington facilities achieved commercial operations. We made equity contributions related to these three projects in the aggregate amount of $75.2 million during 2002 utilizing corporate cash balances and advances under our corporate credit facility.

          Any projects we develop in the future, and those electric generating facilities we may seek to acquire, are likely to require substantial capital investment. Our ability to arrange financing on a non-recourse basis and the cost of such capital are dependent on numerous factors. These factors include, but are not limited to, general economic and market conditions, conditions in the independent power generation market, and investor confidence and credit availability in our industry. In order to access capital on a non-recourse basis in the future, we may have to make larger equity investments in, or provide more financial support for, the project entity.

     Redemptions and Repurchases of Senior Notes Due 2004

          During March 2002, we redeemed $20.0 million of our unsecured senior notes due 2004 as required by the terms of the indenture under which these notes were issued. During the fourth quarter of 2002 and the first quarter of 2003, we repurchased approximately $20.3 million of our senior notes due 2004. As permitted by the provisions of the indenture under which we issued our 2004 senior notes, we credited the principal amount of notes we repurchased against our obligation to make a sinking fund payment on March 15, 2003 to the indenture trustee for the purpose of funding the redemption of $20.0 million of these senior notes.

     Equipment Commitments

          We currently have commitments with turbine and other equipment suppliers to purchase a set of three combustion/steam turbines and heat recovery steam generators. We have made cumulative payments of $165.3 million with remaining payments of $22.5 million due in 2003 under these commitments. We are currently storing the turbine engines and generators and most of the accessories related to this equipment. During the year ended December 31, 2002, we recognized a $30.0 million charge to write-down the cost of one set of these turbines and heat recovery system generators to fair value. The impairment charge consisted of capitalized costs associated with payments previously made. See "- Critical Accounting Policies - Long-Lived Assets."

     Project Level Defaults

          Cogentrix Energy's project subsidiaries which own the Southaven, Caledonia and Dominican Republic facilities are in default of their senior project debt aggregating $947.2 million as of December 31, 2002. As a result, this project debt is callable and classified as a current liability in our consolidated financial statements as of December 31, 2002. In addition, Cogentrix Energy's project affiliate which owns the Sterlington facility is in default of its project debt. The Sterlington facility is accounted for under the equity method and accordingly, the facility's assets and related liabilities, including long-term debt are reflected net as an investment in unconsolidated project affiliates in our consolidated financial statements. The debt for these four facilities is non-recourse to Cogentrix Energy and, therefore, the lenders to these projects cannot look to Cogentrix Energy or any other project subsidiaries or affiliates for the repayment of these obligations and can only look to the applicable project assets of these project subsidiaries (book value of approximately $1.2 billion as of December 31, 2002 for our Southaven, Caledonia and Dominican Republic facilities) to satisfy these obligations. While these lenders do not have direct recourse to Cogentrix Energy, these defaults by our project subsidiaries and project affiliates can still have important consequences for our results of operations and liquidity, including, without limitation:

     Shareholder Dividends and Loans

          On February 14, 2002, our board of directors declared a dividend on our outstanding common stock of $13.5 million payable to shareholders of record as of March 31, 2002. The dividend was paid on April 1, 2002. The board of directors' policy, which is subject to change at any time, provides for a dividend payout ratio of no more than 20% of our net income for the immediately preceding fiscal year. As a result of the event of default under the corporate credit facility triggered by the going concern uncertainty expressed by our independent auditors in their report on our consolidated financial statements, we are currently unable to pay dividends or make other distributions to our shareholders.

          Cogentrix Energy has a revolving credit facility whereby each of its shareholders may borrow from time to time up to $2.0 million from Cogentrix Energy on a revolving basis. Shareholder borrowings accrue interest at the prime rate of a major United States bank plus 1.0%. Principal payments on any borrowings made under the facility are due in three equal annual installments together with accrued interest on the next three shareholder dividend payment dates following the borrowing. As of the date of this filing, approximately $4.7 million is outstanding under the shareholder revolving credit facility. In addition, one shareholder has $3.0 million in outstanding borrowings with Cogentrix Energy that are outside the revolving credit facility. As a result of the event of default under the corporate credit facility triggered by the going concern uncertainty expressed by our independent auditors in their report on our consolidated financial statements, we are currently unable to make additional loans to our shareholders.

Cash Flow from Our Project Subsidiaries and Project Affiliates

          The ability of our project subsidiaries and project affiliates to pay management fees, dividends and distributions periodically to Cogentrix Energy is subject to limitations imposed by various financing documents. These limitations generally require that: (1) debt service payments are current; (2) historical and projected debt service coverage ratios are met; (3) all debt service and other reserve accounts are funded at required levels; and (4) there are no defaults or events of default under the relevant financing documents. There are also additional limitations that are adapted to the particular characteristics of each project subsidiary and project affiliate. Events of default and other circumstances currently exist at certain project subsidiaries or project affiliates that are in some cases eliminating or blocking the payment of management fees, dividends and distributions to Cogentrix Energy. In addition, certain facilities achieving commercial operations and the termination and modification of certain other facilities' power sales agreements have changed the source of where Cogentrix Energy expects to receive management fees, dividends and distributions in the future. These circumstances are described in detail below.

     Termination or Modification of Certain Power Sales Agreements at Some of Our Facilities

          The power sales agreements for our Roxboro and Southport facilities terminated in December 2002 and we are currently selling power produced at these facilities at a significantly reduced level of payments from our power purchaser under one-year agreements that expire in December 2003. See additional discussion at "Business - Description of Facilities in Which We Own a Significant Economic Interest - Roxboro and Southport, North Carolina Facilities". In addition, the power sales agreements for our Portsmouth and Hopewell facilities provide for a significant reduction in fixed capacity payments after December 2002. As a result, Cogentrix Energy will experience a significant reduction in the aggregate amount of distributions from these facilities in the current fiscal year and in subsequent fiscal years. See "- Effects and Trends Affecting Our Financial Condition and Results of Operations - Termination or Modification of Certain Power Sales Agreements at Some of Our Facilities."

     Caledonia and Southaven Facility Defaults

          The Caledonia and Southaven facilities are currently under construction and are scheduled to be completed by mid-2003. Our project subsidiaries are currently in default of their non-recourse project loan agreements as a result of NEG, the guarantor of the conversion services agreement at our Caledonia and Southaven facilities, being downgraded (during August 2002) below investment grade creating an event of default under our conversion services agreements by our purchaser, PG&E Energy Trading-Power, L.P. ("PGET"). The project lenders are not obligated to continue funding construction draws and have the right to exercise all remedies available to them under the applicable project loan agreement, including foreclosing upon and taking possession of all of the applicable project assets. Until the event of default under the project loan agreements are cured and we convert the Southaven constrution loan to a term loan, our project subsidiaries will be unable to make any distributions to Cogentrix Energy. These projects could remain in default for an extended period of time until we can provide a replacement conversion services or power purchaser or refinance the project loan agreements. However, there can be no assurances that we will be able to enter into a replacement conversion services or power purchaser or refinance the project loan agreements. As a result of these events of default, these facilities' non-recourse project debt is callable and has been classified as a current liability in our consolidated financial statements as of December 31, 2002. The project lender to each of these facilities is able to satisfy this obligation with the applicable project's assets only and cannot look to Cogentrix Energy or its other subsidiaries to satisfy this obligation.

           On February 4, 2003, our project subsidiaries for both facilities received a notice from PGET of PGET's intention to terminate the conversion services agreements alleging our project subsidiaries failed to properly interconnect our facilities to the applicable transmission systems. This notice indicated that the conversion services agreements would terminate on March 6, 2003 and that PGET did not intend to continue to perform under the agreements after February 6, 2003. On February 7, 2003, the project subsidiaries filed an emergency petition to compel arbitration or, in the alternative, for a temporary restraining order and preliminary injunction in the Circuit Court for Montgomery County, Maryland. By order dated February 7, 2003, the court denied our petition for a temporary restraining order and set the remaining aspects of the petition for hearing.

          On March 5, 2003, the Circuit Court ruled that PGET was required to comply with the arbitration provisions of the conversion services agreements. The court further ordered that PGET and the project subsidiaries continue to perform their obligations under the conversion services agreements during the pendency of the disputes and the arbitration proceedings. On March 7, 2003, PGET filed an emergency motion to stay the court's ruling, which compels performance pending their appeal of the Circuit Court ruling in the Court of Special Appeals of Maryland. 'This motion was denied on March 11, 2003. PGET's appeal of the lower court ruling is currently scheduled to be heard in the Court of Special Appeals of Maryland on May 12, 2003. On March 24, 2003, PGET issued a Demand for Arbitration to resolve the disputes. PGET and our project subsidiaries are currently performing their obligations under the conversion services agreements. In the event arbitration is unsuccessful and the conversion service agreements are terminated, our project subsidiaries may be required to purchase the test gas and sell test energy. The termination of the conversion services agreements would create additional events of default under the applicable non-recourse loan agreements.

          In the event the conversion services agreements at these facilities are terminated or our conversion services purchaser is unable to meet its obligations to us, we may be required to operate these facilities as merchant generating facilities. Operating these facilities as merchant electric generating facilities would add additional risks including commodity risk exposure with changing commodity prices for the natural gas we utilize as fuel and fluctuating prices for the electricity we would be selling in the open market. In addition, we would be subject to additional costs, risks and requirements to post additional credit support in conjunction with obtaining short to intermediate term contracts to sell our power, to procure fuel supply and transportation agreements and obtain electrical transmission arrangement.

     Sterlington Facility

          Our project affiliate is currently in default under its non-recourse project loan agreements as a result of the credit ratings of Dynegy Holdings, Inc. ("Dynegy"), the guarantor of the conversion services agreement at our Sterlington facility, being downgraded (during July 2002) below investment grade creating a purchaser event of default under our conversion services agreement. During October 2002, our Sterlington project subsidiary and the project lenders amended the non-recourse loan agreement to require all excess cash generated by the facility to be utilized to repay the outstanding borrowings on a quarterly basis during the remaining term of the Sterlington facility's loan agreement (through August 2007). Management does not expect to receive distributions from this project affiliate until the non-recourse project debt can be refinanced. Until then the project lenders continue to have the right to exercise all remedies available to them under the project loan agreements including foreclosing upon and taking possession of all project assets. The Company accounts for this project using the equity method of accounting, and this facility's assets and related liabilities, including long-term debt, are reflected net as an investment in unconsolidated affiliates in the accompanying consolidated balance sheets. The Company's investment in this project was approximately $2.6 million as of December 31, 2002.

     Dominican Republic Facility

          Our project subsidiary that owns our Dominican Republic facility has notified the power purchaser, Corporación Dominicana de Electricidad ("CDE"), on several occasions since the facility achieved commercial operations in March 2002 of events of default under the power purchase agreement based on CDE's failure to pay amounts due for the sale of capacity and electricity (collectively, the "Payment Defaults"). As of the date of this filing, Payment Defaults existed relating to the August 2002 through January 2003 invoices totaling approximately $30.8 million. We have notified the State of the Dominican Republic ("SDR"), the guarantor of CDE's payment obligations, of defaults under the project subsidiary's implementation agreement with the SDR related to a portion of these amounts overdue by CDE. As a result of these Payment Defaults by CDE's and SDR's failure to honor its guarantee of CDE's obligation to make these payments to us, our project subsidiary has exercised its right under the power purchase agreement to suspend operation of the facility pending cure of these Payment Defaults. The lack of payment by the SDR or CDE created events of default under the project subsidiary's non-recourse loan agreement and the lenders currently have the right to exercise all remedies available to them including foreclosing upon and taking possession of all project assets. As a result of these events of default, this non-recourse project debt is currently callable and has been classified as a current liability in our consolidated financial statements as of December 31, 2002. The project lender to this facility is able to satisfy this obligation with the Dominican Republic facility's project assets only and can not look to Cogentrix Energy or its other subsidiaries to satisfy their debt. Until the event of default under the project loan agreement is cured, our project subsidiary will be unable to make distributions to Cogentrix Energy. Continued slow payment by CDE and the SDR in the future may increase our project subsidiary's working capital needs and delay distributions to Cogentrix Energy. We will continue to attempt to collect amounts past due from CDE or the SDR and will continue to exercise all of the rights and remedies we have available to us under the power purchase agreement, the implementation agreement and the SDR guarantee, including terminating the power purchase agreement. The termination of this agreement by our project subsidiary would require a termination payment by CDE or the SDR equal to the outstanding debt, invested capital by the project partners and other termination costs as defined in the power purchase agreement. Because the obligation is unsecured, we cannot give any assurances that we will be able to collect the termination payment from CDE or the SDR.

          Due to the ongoing payment defaults and the corresponding CDE and SDR defaults under the project subsidiary's non-recourse loan agreements, the project lenders have the right to delay the conversion of the outstanding borrowings from construction loans to term loans ("Conversion"). The failure of the project subsidiary to achieve Conversion on or before March 28, 2003 has resulted in an additional event of default under the project loan agreement. So long as the borrowings under the loan agreements remain as construction loans, our project subsidiary will be prohibited from making distributions to Cogentrix Energy.

     Cogentrix Eastern America

          Our intermediate, wholly-owned subsidiary, Eastern America, which was formed to hold interests in electric generating facilities acquired in 1998 and 1999, amended the revolving credit facility it has with a financial institution during September 2002. The total outstanding amount of $60.0 million was extended and converted to a term loan with principal payments due quarterly through the final maturity date of September 30, 2005. The amended Eastern America credit facility is secured by, among other things, a pledge of the Eastern America capital stock and the capital stock of the project subsidiaries that hold the Company's investment in our Northampton and Logan projects as well as the dividends, distributions and other payments made to the Company by the Northampton, Logan, Indiantown and Carneys Point projects. The amended credit agreement requires Eastern America to continue to accumulate in escrow, the distributions received from these four project affiliates (collectively, the "Significant Affiliates") until the amounts accumulated in escrow reach $6.0 million. If more than $6.0 million has been accumulated in escrow, such excess can be distributed to Eastern America prior to May 15, 2003, even if it could not otherwise be distributed if such restriction is solely a result of the Indiantown facility's inability to make distributions (see additional discussion below). At June 30, 2003, if certain conditions exist at certain of the Significant Affiliates which prevent those Significant Affiliates from making distributions to Eastern America, the entire $6.0 million held in escrow and, as long as any such conditions exist, any future distributions from those Significant Affiliates will be used to prepay debt. If at June 30, 2003, these conditions do not exist and the Significant Affiliates are able to make distributions to Eastern America, $3.0 million of the funds in escrow will be utilized to prepay outstanding borrowings with the remaining amount in escrow distributed to Eastern America and ultimately to Cogentrix Energy. In addition, if an event of default occurs under the project loan agreements for certain of Eastern America's project affiliates, a corresponding event of default would be triggered under the Eastern America credit agreement. See "-Events and Trends Affecting Our Financial Condition and Results of Operations - PG&E National Energy Group, Inc."

     Indiantown Facility

          During December 2002, certain letters of credit posted to secure certain of the Indiantown facility's operating obligations were drawn upon and converted to loans ("L/C Loans") when the bank that provided these letters of credit did not extend the terms of these letters of credit past their original expiration date. The Indiantown facility will be prohibited from making distributions to Eastern America (and ultimately, to Cogentrix Energy) until these L/C Loans (currently $11.7 million) are repaid in full or replacement letters of credit are obtained.

          The Indiantown facility also has posted a letter of credit in the amount of approximately $30.0 million, which together with cash in the debt service reserve account, represents the required debt service reserve. The bank that issued this letter of credit has notified the Indiantown facility of its intention not to extend the term of this letter of credit, which is due to expire in November 2005. As a result, unless a replacement letter of credit provider is obtained, the Indiantown facility will be prohibited from making distributions to Eastern America (and ultimately, to Cogentrix Energy) until the Indiantown facility has fully funded the debt service reserve account. The remaining balance to be funded into this reserve account is approximately $30.0 million.

          The Company's management believes that the Indiantown facility will be able to enter into arrangements to obtain all of these letters of credit from replacement letter of credit providers. There can be no assurances, however, that the Indiantown facility will be able to obtain such replacement letters of credit.

Impact of Energy Price Changes, Interest Rates and Inflation

          Energy prices are influenced by changes in supply and demand, as well as general economic conditions, and therefore tend to fluctuate significantly. We attempt to protect against the risk of changes in the market price for electricity by entering into contracts with fuel suppliers, utilities or power marketers that reduce or eliminate our exposure to this risk by establishing future prices and quantities for the electricity produced independent of the short-term market. Through various hedging mechanisms, we have attempted to mitigate the impact of changes on the results of operations of most of our projects. The hedging mechanism against increased fuel and transportation costs for most of our currently operating facilities is to provide contractually for matching increases in the energy payments our project subsidiaries receive from the utility purchasing the electricity generated by the facility.

          Under the power sales agreements for certain of our facilities, energy payments are indexed, subject to certain caps, to reflect the purchasing utility's solid fuel cost of producing electricity or provide periodic, scheduled increases in energy prices that are designed to match periodic, scheduled increases in fuel and transportation costs that are included in the fuel supply and transportation contracts for the facilities.

          Most of our facilities that recently achieved commercial operations or are currently under construction have conversion services arrangements in place to minimize the impact of fluctuating fuel prices. Under these conversion services arrangements, each conversion services purchaser is typically obligated to supply and pay for fuel necessary to generate the electrical output expected to be dispatched by the customer. See additional discussion regarding our conversion services agreements at our Southaven and Caledonia facilities at "Cash Flow From our Project Subsidiaries and Project Affiliates - Caledonia and Southaven Facility Defaults."

          Changes in interest rates could have a significant impact on our results of operations because they affect the cost of capital needed to construct projects as well as interest expense of existing project financing debt. As with fuel price escalation risk, we attempt to hedge against the risk of fluctuations in interest rates by arranging either fixed-rate financing or variable-rate financing with interest rate swaps or caps on a portion of our indebtedness.

          Although hedged to a significant extent, our financial results will likely be affected to some degree by fluctuations in energy prices, interest rates and inflation. The effectiveness of the hedging techniques implemented by us is dependent, in part, on each counterparty's ability to perform in accordance with the provisions of the relevant contracts.

Critical Accounting Policies

     General

          We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States. This involves the use of certain estimates, judgments and assumptions which affect the reported amounts of assets and liabilities as well as revenues and expenses during the periods reported. We have identified several critical accounting policies which are significant factors to understanding and evaluating the consolidated financial statements. These key items are discussed in the following paragraphs.

     Long-Lived Assets

          We evaluate our long-lived assets, including electric plants and related equipment, for possible impairment based on the projection of undiscounted cash flows, when a change in circumstances or events indicate that the carrying amount of an asset or group of assets may no longer be recoverable. Estimates of future cash flows used to test the recoverability of specific long-lived assets are based on expected cash flows from the use and eventual disposition of the assets. A significant reduction in actual and estimated cash flows, including the inability to bring the asset to its intended use, could have a material adverse impact on the consolidated financial results. We executed agreements during 2001 to purchase three sets of turbines and heat recovery steam generators with an original intent of placing this equipment in a new electric generating facility under development. During 2002, the electric generating industry experienced a number of adverse events and circumstances including the overbuild of electric generating. As a result of these factors, we reassessed the utilization of this equipment and currently intend to place two of the three turbine and generator sets in the expansion of one of our existing facilities. We have prepared a cash flow model for an expansion project, including the costs to place this equipment in service, and have concluded that the projected undiscounted cash flows from the expanded facility will be adequate to recover the carrying value of the equipment including the capital cost to place this equipment in service. Accordingly, under the provisions of Statement of Financial Accounting Standards ("SFAS") No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", the carrying value of these two sets of turbines and generators is deemed to be recoverable and no impairment charge is warranted. We are currently uncertain regarding the placement of the third turbine and generator set and have determined that the carrying value of this equipment will not be recoverable. We obtained an appraisal of the fair value of this third set of equipment and in accordance with the provision of SFAS No. 144, recorded an impairment charge of $30.0 million for the year ended December 31, 2002 to write-down it value to its appraised fair value.

          In addition, we have reassessed the use of the Caledonia and Southaven facilities as a result of the events discussed above under "- Liquidity and Capital Resources - Cash Flows From Our Project Subsidiaries and Project Affiliates - Caledonia and Southaven Facility Defaults." As indicated, we intend to operate these facilities as merchant plants in the event our conversion services agreements are terminated or our conversion services purchaser is unable to meet its obligations to us. We have prepared a merchant cash flow model for the Caledonia and Southaven facilities and have concluded that the projected undiscounted cash flows from these facilities will be adequate to recover the carrying value of each facility's long-lived assets. Accordingly, under the provisions of SFAS No. 144, the carrying value of these long-lived assets is deemed to be recoverable and no impairment charge is warranted.

     Property, Plant and Equipment and Other Depreciable Assets

          Property, plant and equipment is recorded at cost and depreciated over its estimated useful life. The original estimated useful lives of our facilities can reach a maximum of 30 years. A significant decrease in the estimated useful life of one or more facilities could have a material adverse impact on our operating results in the period in which the estimate is revised as well as future periods.

     Investments in Unconsolidated Affiliates and Related Purchase Price Premiums

          We account for our investments in 10 unconsolidated power projects under the equity method of accounting. We use the guidance in Accounting Principles Board Opinion No. 18, "The Equity Method of Accounting for Investments in Common Stock" to assess the carrying value of our investments and the related purchase price premiums related to these investments. As of December 31, 2002, there were no impairments of the carrying value of any of 'our equity investments. If events occur that would significantly reduce future income and cash flows from these projects, however, they could have a material adverse impact on the consolidated results of operations.

Interest Rate Sensitivity

          The following tables provide information about our derivative and other financial instruments that are sensitive to changes in interest rates, including interest rate swaps and debt obligations. The table contains information on the interest rate sensitivity of our debt portfolio. This table presents principal cash flows and related weighted average interest rates by expected maturity dates for all of our debt obligations as of December 31, 2002 (excluding our interest rate swap agreements). This table does not reflect scheduled future interest rate adjustments. The weighted average interest rates disclosed in the table are calculated based on interest rates as of December 31, 2002. Future interest rates are likely to vary from those disclosed in the table.

          The following tables contain information as of December 31, 2002, regarding interest rate swap agreements entered into by some of our project subsidiaries to manage interest rate risk on their variable-rate project financing debt. The tables do not include similar agreements maintained at unconsolidated power projects. The notional amounts of debt covered by these agreements as of December 31, 2002, was $459,352,000. These agreements effectively changed the interest rate, including applicable margins, on the portion of debt covered by the notional amounts from a weighted average variable rate of 2.87% to a weighted average effective rate of 5.00% at December 31, 2002.

(1)     The "variable rate receive" and "actual interest rate" are based on the interest rates in effect as of
          December 31, 2002. Interest rates in the future are likely to vary from those disclosed in the tables above.

Item 8. Financial Statements and Supplementary Data

In addition, certain financial statements required by Item 3-09 of Regulation S-X have been filed as exhibits to this Annual Report on Form 10-K and are incorporated herein by reference.


Schedules other than those listed above have been omitted, since they are not required, are not applicable or are unnecessary due to the presentation of the required information in the financial statements or notes thereto.

The Board of Directors
Cogentrix Energy, Inc.:

We have audited the 2002 consolidated financial statements of Cogentrix Energy, Inc. and subsidiaries as listed in the accompanying index. In connection with our audit of the 2002 consolidated financial statements, we also have audited the 2002 financial statement schedule as listed in the accompanying index. These consolidated financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audit. We did not audit the financial statements of certain unconsolidated non-subsidiary investee companies. The Company's investment in these non-subsidiary investee companies at December 31, 2002 was $158.3 million and its equity in earnings of these non-subsidiary investee companies was $21.4 million for the year ended December 31, 2002. The financial statements of these non-subsidiary investee companies were audited by other auditors whose reports (one of which contains an explanatory paragraph related to a non-subsidiary investee's ability to continue as a going concern; another of which contains an explanatory paragraph related to the non-subsidiary investee's change in method of accounting for certain derivative contracts) have been furnished to us, and our opinion, in so far as it relates to the amounts included for the non-subsidiary investees, is based solely on the report of the other auditors. The 2001 and 2000 consolidated financial statements and financial statement schedule of Cogentrix Energy, Inc. as listed in the accompanying index were audited by other auditors who have ceased operations. Those auditors' report, dated February 7, 2002, except with respect to the matters discussed in the first paragraph of Note 7 as to which the date was April 12, 2002, on those consolidated financial statements and financial statement schedule was unqualified and included an explanatory paragraph that described the change in the Company's method of accounting for derivative instruments and hedging activities.

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, based on our audit and the reports of other auditors, the 2002 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Cogentrix Energy, Inc. and subsidiaries as of December 31, 2002, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the related 2002 financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in note 3 to the consolidated financial statements, effective January 1, 2002, the Company changed its method of accounting for goodwill and other intangible assets. Also, effective April 1, 2002, the Company adopted new accounting standards to account for certain derivative contracts.

The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern. As discussed in note 2 to the consolidated financial statements, the Company has significant financial obligations which come due or are callable within the next year. This matter raises substantial doubt about the ability of the Company to continue as a going concern. Management's plans in regard to this matter is also described in note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

                                                                                                                /s/ KPMG LLP       
March 26, 2003
Charlotte, North Carolina

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

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

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

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

1.  NATURE OF BUSINESS

          Cogentrix Energy, Inc. ("Cogentrix Energy") and subsidiary companies (collectively, the "Company") are principally engaged in the business of acquiring, developing, owning and operating independent power generating facilities (individually, a "Facility," or collectively, the "Facilities"). As of December 31, 2002, the Company owned or had interests in 24 Facilities in operation in the United States and one in the Dominican Republic with an aggregate installed capacity of approximately 6,075 megawatts. After taking into account the partial interests in the 19 plants that are not wholly-owned by the Company, which range from 1.6% to 74.2%, the Company's net ownership interest in the total production capability of the 25 Facilities in operation is approximately 3,269 megawatts. Electricity generated by each Facility is sold to electric utilities or power marketers (the "Electric Customer") and steam produced by primarily all Facilities is sold to an industrial company (the "Steam Purchaser"), all under long-term contractual agreements.

          As of December 31, 2002, the Company owned two Facilities under construction in Mississippi with an expected aggregate production capability of 1,620 megawatts (see Note 11 for additional discussion regarding our ownership interest in the Caledonia Facility).

2.  BASIS OF PRESENTATION

          The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern which contemplates the continuity of operations, realization of assets and the satisfaction of liabilities in the ordinary course of business. However, as a result of the maturity of $247.5 million of outstanding obligations under Cogentrix Energy's Corporate Credit Facility (see Note 7) in October 2003, the realization of assets and the satisfaction of liabilities are subject to uncertainty. Management of the Company intends to refinance these obligations and is currently negotiating the terms of a restructured facility. However, there are no assurances that this restructuring can be accomplished. In addition, the independent auditor's report which contains an explanatory paragraph related to a going concern uncertainty issued on these consolidated financial statements created an event of default under the Corporate Credit Facility. There can be no assurances that the lenders to the Corporate Credit Facility will not accelerate and demand immediate payment of all amounts due as a result of the event of default. In the event the lenders to the Corporate Credit Facility accelerate the outstanding obligations, or if the Corporate Credit Facility matures and is not paid, this would create a cross-default under the 2004 and 2008 Notes (see Note 7), and the senior note holders would have the ability to accelerate the $400.6 million of senior notes outstanding as of December 31, 2002 and demand immediate payment.

          Cogentrix Energy is a management company that derives cash flow from its operating subsidiaries. Management of the Company believes that cash currently on hand and expected 2003 cash flows from these subsidiaries will be adequate for Cogentrix Energy to meet its non-contingent contractual obligations and its other 2003 operating obligations including debt service on its 2004 and 2008 Notes (see Note 7), interest and fees related to the Corporate Credit Facility and recurring general and administrative costs. However, this belief is based on a number of material assumptions, including, without limitation, the continuing ability of the Company's subsidiaries and project affiliates to pay dividends, management fees and other distributions and the ability to refinance the Corporate Credit Facility. Additional liquidity could be provided through the sale of selected project assets. There is no assurance that these sources will be available when needed or that Cogentrix Energy's actual cash requirements will not be greater than anticipated.

          The Company's Southaven, Caledonia and Dominican Republic facilities are in default of their senior, non-recourse project debt aggregating $947.2 million as of December 31, 2002 as a result of the factors described in Note 8. As a result, these Facilities' non-recourse project debt is callable and has been classified as a current liability in the accompanying consolidated balance sheets as of December 31, 2002. The project lenders are not obligated to continue funding construction draws and have the right to exercise all remedies available to them under the applicable project loan agreement, including foreclosing upon and taking possession of all of the applicable project assets. Until the event of default under the applicable project loan agreements are cured, our project subsidiaries will be unable to make any distributions to Cogentrix Energy. These projects could remain in default for an extended period of time until we can refinance the project loan agreements or provide a replacement conversion services or power purchase agreement. However, there can be no assurances that we will be able to enter into a replacement conversion services or power purchase agreement or refinance the project loan agreements. The project lender to each of these Facilities is able to satisfy this obligation with the applicable project's assets only (total assets of approximately $1.2 billion as of December 31, 2002) and cannot look to Cogentrix Energy or its other subsidiaries to satisfy this obligation. While these lenders do not have direct recourse to Cogentrix Energy, these defaults may still have important consequences for our results of operations and liquidity, including, without limitation:

3.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

          Principles of Consolidation - The accompanying consolidated financial statements include the accounts of Cogentrix Energy and its subsidiary companies. Wholly-owned and majority owned subsidiaries, including a 50%-owned entity in which the Company has effective control through its designation as the managing partner of this project, are consolidated. Less-than-majority-owned subsidiaries in which the Company exercises significant influence are accounted for using the equity method. Investments in unconsolidated affiliates in which the Company has less than a 20% interest and does not exercise significant influence over operating and financial policies are accounted for under the cost method. All material intercompany transactions and balances among Cogentrix Energy, its subsidiary companies and its consolidated joint ventures have been eliminated in the accompanying consolidated financial statements.

          Cash and Cash Equivalents - Cash and cash equivalents include bank deposits, commercial paper, government securities and certificates of deposit that mature within three months of their purchase. Amounts in debt service accounts and the proceeds remaining from draws on construction contractor letters of credit which might otherwise be considered cash equivalents are treated as current restricted cash.

          Inventories - Coal inventories consist of the contract purchase price of coal and all transportation costs incurred to deliver the coal to each Facility. Gas and fuel oil inventories represent the cost of natural gas and fuel oil purchased as fuel reserves that are forecasted to be consumed during the next fiscal year. Spare parts inventories consist of major equipment and recurring maintenance supplies required to be maintained in order to facilitate routine maintenance activities and minimize unscheduled maintenance outages and are recorded at average cost. As of December 31, 2002 and 2001, fuel and spare parts inventories were comprised of the following (dollars in thousands):

          Certain fuel inventories are recorded at last-in, first-out ("LIFO") cost of $19.1 million and $18.2 million at December 31, 2002 and 2001, respectively, with the remaining fuel inventories recorded at first-in, first-out ("FIFO") cost. The cost of fuel inventories recorded on a LIFO basis was approximately $0.1 million higher and $1.0 million lower than the cost of these inventories on a FIFO basis as of December 31, 2002 and 2001, respectively. Spare part inventories of $5.2 million and $5.1 million as of December 31, 2002 and 2001, respectively, that are held to minimize unscheduled maintenance outages or that are not expected to be utilized within the next year are classified as other long-term assets in the accompanying consolidated balance sheets.

          The Company holds certain parts and accessories which are to be held and used under a long-term service agreement at certain of our natural gas-fired Facilities (see Note 11 for additional discussion). These parts totaling $28.3 million and $26.9 million, net of depreciation, at December 31, 2002 and 2001, respectively, will be placed into service on scheduled intervals based on the replacement pattern outlined in the long-term service agreements and are included in other long-term assets in the accompanying consolidated balance sheets. These parts are being amortized over a unit of production method based on the replacement pattern under the long-term service agreement.

          Property, Plant and Equipment - Property, plant and equipment is recorded at actual cost. Substantially all property, plant and equipment consists of the Facilities that are depreciated on a straight-line basis over their estimated useful lives up to 30 years. Other property and equipment is depreciated on a straight-line basis over the estimated economic or service lives of the respective assets (ranging from 3 to 40 years). Depreciation expense for years ended December 31, 2002, 2001 and 2000 was $62.3 million, $34.6 million and $43.2 million, respectively. Maintenance and repairs are charged to expense as incurred. Emergency and rotable spare parts are included in plant and are depreciated over the useful lives of the related components. Certain parts currently in service that are covered under long-term service agreements for our combined-cycle, natural gas-fired Facilities are depreciated under a units of production method based on the replacement pattern under the long-term service agreement.

          Construction in Progress - Construction progress payments, engineering costs, insurance costs, wages, interest and other costs relating to construction in progress are capitalized. Construction in progress balances are transferred to property, plant and equipment when the assets are ready for their intended use. Interest is capitalized on projects during the advanced stages of development and the construction period. For the years ended December 31, 2002, 2001 and 2000, the Company capitalized $36.9 million, $54.9 million and $26.6 million, respectively, of interest in connection with the development and construction of power plants.

          Deferred Financing Costs - Financing costs, consisting primarily of commitment fees, legal and other direct costs incurred to obtain financing, are deferred and amortized over the expected financing term.

          Investments in Unconsolidated Affiliates - Investments in unconsolidated affiliates include investments in entities that own or derive revenues from power projects currently in operation or under construction. The Company's share of income or loss from investments in operating power projects is included in operating revenue in the accompanying consolidated statements of income.

          Project Development Costs - The Company capitalizes project development costs once it is determined that it is probable that such costs will be realized through the ultimate construction of a power plant. These costs include professional services, salaries, permitting and other costs directly related to the development of a new project. These costs are generally transferred to construction in progress when financing is obtained, or expensed when the Company determines that a particular project will no longer be developed. Capitalized costs are amortized over the estimated useful life of the project. Project development costs at December 31, 2002 and 2001 were $0 and $9.7 million, respectively. The Company recorded charges of approximately $13.4 million, $10.1 million and $3.1 million for the years ended December 31, 2002, 2001 and 2000, respectively, related to the write-off of costs capitalized for certain projects under development which are no longer considered viable. These charges are included in general, administrative and development expenses in the accompanying consolidated statements of income.

          Revenue Recognition and Concentration of Credit Risk - Revenues from the sale of electricity, service and steam are recorded based upon output delivered and capacity provided at rates specified under contract terms. Lease revenues on "sales-type" capital leases are amortized into income using the effective interest rate method over the life of the respective power sales agreements and lease revenues from operating leases are recognized on a straight-line basis over the life of the respective power sales or conversion services agreements. Significant portions of the Company's revenues have been derived from three electric utility customers during the last three years. These customers accounted for 36%, 14% and 8% of the Company's interest in the aggregate revenues of the Company's consolidated and unconsolidated subsidiaries in the year ended December 31, 2002, 43%, 17% and 11% of revenues in the year ended December 31, 2001 and 40%, 17% and 13% of revenues in the year ended December 31, 2000. Included in accounts receivable at December 31, 2002, are $42.7 million of accounts receivable from a quasi-governmental entity located in the Dominican Republic. See Note 8 for additional discussion.

          Income Taxes - Deferred income tax assets and liabilities are recognized for the estimated future income tax effects of temporary differences between the tax bases of assets and liabilities and their reported amounts in the financial statements. Deferred tax assets are also established for the estimated future effect of net operating loss and tax credit carryforwards when it is more likely than not that such assets will be realized. Deferred taxes are calculated based on provisions of the enacted tax law. Deferred tax assets are reduced by a valuation allowance to the extent the Company concludes there is uncertainty as to their ultimate realization.

          Start-Up Activities - Start-up activities, including initial activities related to opening a new Facility, initiating a new process in an existing Facility and activities related to organizing a new entity (commonly referred to as organization costs), are expensed as incurred.

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

          Derivative Instruments and Hedging Activities - On January 1, 2001, the Company adopted the Financial Accounting Standards Board ("FASB") Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133, as amended, requires the fair value of derivative instruments to be recorded on the balance sheet as an asset or liability. Changes in the fair value of derivative financial instruments are either recognized periodically in income or shareholder's equity (as a component of other comprehensive income), depending on whether the derivative is being used to hedge changes in fair value or cash flow. The Company uses derivative instruments to manage the risk that changes in interest rates will affect the amount of future interest payments. The Company engages in interest rate swap agreements, under which the Company agrees to pay fixed rates of interest. The differential paid or received under these agreements is recognized as an adjustment to interest expense. These contracts are considered hedges against fluctuations in future cash flows associated with changes in interest rates. Accordingly, the interest rate swaps were recorded in other long-term liabilities in the accompanying consolidated balance sheet at their fair values. The fair value of the Company's derivatives is determined by reference to market values from various third party sources. The adoption of SFAS No. 133 resulted in a deferred loss of $4.4 million, net of deferred taxes, which was recorded as a cumulative effect of a change in accounting principle in other comprehensive income on the accompanying consolidated statement of changes in shareholders' equity. For the years ended December 31, 2002 and 2001, the Company recorded approximately $7.9 million and $3.7 million, respectively, net of deferred taxes, in net deferred losses related to its interest rate swaps in other comprehensive income. The fair value of the Company's interest rate swap agreements related to the consolidated subsidiaries was an obligation of $13.0 million and $4.7 million as of December 31, 2002 and 2001, respectively, and are included in other long-term liabilities in the accompanying consolidated balance sheets. In addition, the Company's share of the fair value of the interest rate swap agreements related to our unconsolidated subsidiaries was an obligation of $15.2 million and $8.9 million, respectively, at December 31, 2002 and 2001 and is included as a reduction to investments in unconsolidated affiliates in the accompanying consolidated balance sheets. The Company currently has interest rate swaps that mature from 2003 through 2006. The Company identified various other financial instruments and contracts that did not meet the definition of a derivative under SFAS No. 133 or were excluded from the accounting treatment of SFAS No. 133 as a result of qualifying for the normal purchases and sales exception.

          On April 1, 2002, the Company implemented two interpretations issued by the FASB Derivatives Implementation Group ("DIG"). DIG Issues C15 and C16 changed the definition of normal purchases and sales included in SFAS No. 133. Previously, certain derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business were exempt from the requirements of SFAS No. 133 under the normal purchases and sales exception, and thus were not marked to market and reflected on the balance sheet like other derivatives. Instead, these contracts were recorded on an accrual basis. DIG Issue C15 changed the definition of normal purchases and sales for certain power contracts. DIG Issue C16 disallowed normal purchases and sales treatment for commodity contracts (other than power contracts) that contain volumetric variability or optionality. The Company determined that one of its investments in unconsolidated affiliates in which the Company owns a 50% interest has a derivative commodity contract for the physical delivery of power which no longer qualifies for normal purchases and sales treatment under these interpretations. Beginning April 1, 2002, this contract was required to be recorded on the balance sheet at fair value and marked to market through earnings. The Company recorded a $0.6 million benefit, net of tax, from the adoption of these interpretations as a cumulative effect of a change in accounting principle as of April 1, 2002, in the accompanying consolidated statements of income. The FASB continues to issue guidance that could affect the Company's application of SFAS No. 133 and require adjustments to the amounts and disclosures in the consolidated financial statements.

          Goodwill and Other Intangibles - On January 1, 2002, the Company adopted SFAS No. 142, "Goodwill and Other Intangible Assets," which supersedes Accounting Principles Board ("APB") Opinion No. 17, "Intangible Assets." SFAS No. 142 addresses how intangible assets that are acquired individually or with a group of other assets (but not those acquired in a business combination) should be accounted for in financial statements upon their acquisition, and addresses how goodwill and other intangible assets should be accounted for after they have been initially recognized in the financial statements. SFAS No. 142 eliminates the requirement to amortize goodwill and other intangible assets that have indefinite useful lives, instead requiring the assets to be tested at least annually for impairment based on the specific guidance in SFAS No. 142. The Company prepared a transition impairment test of goodwill and other intangibles in conjunction with the initial adoption and no impairment was indicated. The Company has determined that its unamortized goodwill and purchase price premiums have indefinite useful lives and has eliminated the amortization of these assets beginning in 2002. As of January 1, 2002, the Company had unamortized goodwill and unamortized purchase price premiums in unconsolidated power projects totaling $153.1 million. In addition, management continues to assess the carrying value of the purchase price premiums in accordance with APB Opinion No. 18, "The Equity Method of Accounting for Investments in Common Stock," and believes that these intangible assets are recoverable in all material respects. As of December 31, 2002, the Company had not incurred any impairments of goodwill or other intangibles. The table below presents the pro-forma impact of the amortization of goodwill and the purchase price premiums for the years ended December 31, 2002, 2001 and 2000 (dollars in thousands, except per share amounts):

          In conjunction with the adoption of SFAS No. 142, the Company revised its accounting policy related to goodwill and purchase price premiums. Prior to January 1, 2002, goodwill was amortized over its estimated useful life using the straight-line method. Subsequent to January 1, 2002, goodwill is tested for impairment on an annual basis and when other events or circumstances require an impairment test. Impairment losses are recognized whenever the fair value of goodwill is less than its carrying value. Fair value is determined using discounted cash flow analysis.

          Long-Lived Assets - On January 1, 2002, the Company adopted SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." The adoption of this pronouncement had no impact on the accompanying consolidated financial statements. This statement requires that long-lived assets that are to be disposed of by sale be measured at the lower of book value or fair value less cost to sell. The standard also expanded the scope of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity and that will be eliminated from the ongoing operations of the entity in a disposal transaction. The Company reviews its long-lived assets for impairment whenever events occur or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The review is based on various analyses, including undiscounted cash flow projections. An impairment charge is recognized for those assets that are not recoverable. Assets held for sale are recorded at the lesser of book value or fair value less cost to sell. During 2002, the Company recorded an impairment charge related to the carrying value of one set of its turbines and related equipment currently in storage. See Note 4 for additional discussion. In management's opinion, at December 31, 2002, the carrying value of the Company's other long-lived assets is recoverable in all material aspects. Prior to the adoption of SFAS No. 144, the Company accounted for its assets in accordance with SFAS No. 121, "Accounting for Long-Lived Assets and Long-Lived Assets to be Disposed of."

          New Accounting Pronouncements - During June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This statement requires companies to record a liability relating to the retirement and removal of assets used in their business. The liability is discounted to its present value, and the related asset value is increased by the amount of the resulting liability. Over the life of the asset, the liability will be accreted to its future value and eventually extinguished when the asset is taken out of service. The provisions of this statement are effective for the Company on January 1, 2003. Management is currently evaluating the effects of this pronouncement.

          In April 2002, the FASB issued SFAS No. 145, "Rescission of SFAS No. 4, 44 and 64, Amendment of SFAS No. 13 and Technical Corrections." SFAS No. 4 had required all gains and losses from extinguishment of debt to be aggregated and, if material, classified as an extraordinary item, net of related income tax effect. SFAS No. 145 rescinds SFAS No. 4 and the related required classification gains and losses from extinguishment of debt as extraordinary items under certain circumstances. Additionally, SFAS No. 145 amends SFAS No. 13 to require that certain lease modifications that have economic effects similar to sale-leaseback transactions be accounted for in the same manner as sale-leaseback transactions. SFAS No.145 is applicable for the Company beginning January 1, 2003, with the provisions related to SFAS No. 13 for transactions occurring after May 15, 2002. The Company is currently evaluating the impact of adoption of SFAS No. 145.

          In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS No. 146 requires costs associated with exit or disposal activities to be recognized when they are incurred rather than at the date of a commitment to an exit or disposal plan. SFAS No. 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002. The Company is currently evaluating the impact of adoption of SFAS No. 146.

          In November 2002, the FASB issued FASB Interpretation ("FIN") No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," an interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34. This interpretation elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. 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 and are not expected to have a material effect on the Company's consolidated results of operations, financial position or cash flows. This interpretation excludes guarantees provided by and among Cogentrix Energy and its consolidated subsidiaries. The Company adopted the disclosure provisions of this interpretation for the year ended December 31, 2002. See Note 11 for a discussion of the Company's guarantees.

          Reclassifications - Certain amounts included in the accompanying consolidated financial statements as of and for the years ended December 31, 2001 and 2000, have been reclassified from their original presentation to conform with the presentation as of and for the year ended December 31, 2002.

4.  IMPAIRMENT OF LONG-LIVED ASSETS

          Turbines and Other Equipment - The Company has entered into commitments with a turbine supplier and a heat recovery steam generator ("HRSG") supplier to purchase three sets of turbines and HRSGs. The Company has received most of this equipment and is currently storing the equipment. The Company entered into the agreements to purchase this equipment during the first quarter of 2001 with the intent of placing this equipment in a new electric generating facility under development. During 2002, the electric generating industry experienced a number of adverse events and circumstances including the overbuild of electric generating assets. As a result of these factors, management of the Company reassessed the utilization of this equipment and currently intends to place two of three turbine and HRSG sets in the expansion of one of the Company's existing facilities. The Company has prepared a cash flow model for these expansion projects, including the costs to place this equipment in service, and has concluded that the undiscounted cash flows from these expanded facilities will be adequate to recover the carrying value of two sets of turbines and HRSGs including the capital cost to place this equipment in service. Accordingly, under the provisions of SFAS No. 144, the carrying value of theses two sets of turbines and HRSGs are deemed to be recoverable, and no impairment charge is warranted. Management of the Company is currently uncertain regarding the placement of the third turbine and HRSG set and has determined that the carrying value will not be recoverable. The Company obtained an appraisal of the fair value of this remaining equipment and in accordance with the provision of SFAS No. 144, recorded an impairment charge of $30.0 million during the fourth quarter of 2002 which is included in operating costs in the accompanying consolidated statements of income. The charge consisted of previously capitalized costs associated with payments required under the turbine and HRSG supply agreements. As of December 31, 2002, the revised net book value of the three sets of turbines and HRSGs was $130.1 million. The Company expects to make additional progress payments of $30.4 million during 2003 which will be capitalized into the remaining two unimpaired sets of turbines and other equipment basis. Although the Company is attempting to place this equipment in the expansion of one of the Company's existing projects or a new development project, the Company cannot provide any assurances that we will be able to place this equipment. In the event the Company is unsuccessful, the carrying value of this equipment may be further impaired and consequently the Company's results of operations would be adversely affected.

          Southaven and Caledonia Facilities - The Company's project subsidiaries which own the Southaven and Caledonia Facilities are currently in default of their project loan agreements as a result of the PG&E National Energy Group, Inc. ("NEG" and the guarantor of the Facility's conversion services purchaser) default under each Facility's conversion services agreement as discussed in Note 8. In addition, NEG has experienced a financial downturn, is currently in default of various recourse loan obligations and is engaged in restructuring it loans and other agreements. If a restructuring agreement is not reached, NEG and certain of its subsidiaries may be compelled to seek protection or be forced into bankruptcy proceedings under the United States Bankruptcy Code. In the event our conversion services purchasers are brought into bankruptcy proceedings with NEG, significant doubt would arise as to their ability to meet the obligations under the conversion services agreements. As a result, the Company has reassessed the use of theses facilities and intends to operate these facilities as merchant plants in the event our conversion services agreements are terminated. The Company has prepared a merchant cash flow model for each of these Facilities and has concluded that the undiscounted cash flows from these Facilities will be adequate to recover the carrying value of each Facility's long-lived assets. Accordingly, under the provisions of SFAS No. 144, the carrying value of these long-lived assets is deemed to be recoverable, and no impairment charge is warranted. Although the Company intends to operate these Facilities as merchant plants, the Company cannot provide any assurances that the actual cash flows from a merchant plant will be adequate to recover the carrying value of each Facility's long-lived assets. In the event the Company is unsuccessful, the carrying value of these long-lived assets may become impaired and consequently the Company's results of operations would be adversely affected. In addition, these long-lived assets may become impaired as a result of certain conditions discussed in Note 8.

5.  SALES OF PROJECT INTERESTS

          During February 2001, Cogentrix Ouachita Holdings, Inc. ("Ouachita Holdings"), an indirect, wholly-owned subsidiary of Cogentrix Energy and sole member of Quachita Power, LLC ("Quachita Power"), sold a 50% membership interest in Quachita Power (the "Quachita Sale") to an indirect subsidiary of General Electric Capital Corporation ("GECC"). Quachita Power owns an approximate 816-megawatt, combined-cycle, natural gas-fired electric generating facility near the city of Sterlington, Louisiana (the "Sterlington Facility"). In exchange for the membership interest, Ouachita Holdings received $48.3 million in cash and was relieved of $56.3 million of its original equity contribution commitment to Quachita Power. This equity commitment was previously supported by a letter of credit under the Corporate Credit Facility (see Note 7). The Company retained a 50% membership interest in Quachita Power and will continue to manage and operate the Sterlington Facility. The Company recorded a gain of approximately $50.3 million, net of transaction costs related to this sale which is included in gain on sale of project interests, net of transaction costs and other in the accompanying consolidated statements of income. The Company is currently accounting for this investment using the equity method of accounting.

          On March 30, 2001, the Company sold its entire interest in an electric generating facility in Batesville, Mississippi to NRG Energy, Inc. In exchange, the Company received $64.0 million and assigned the operation and maintenance agreement to NRG Energy, Inc. The Company recorded a gain of approximately $8.5 million, net of transaction costs related to this sale which is included in gain on sale of project interests, net of transaction costs and other in the accompanying consolidated statements of income.

6.  INVESTMENTS IN UNCONSOLIDATED POWER PROJECTS

          The Company recognized approximately $42.4 million, $34.8 million and $44.0 million in income from unconsolidated investments in power projects, net of premium amortization in 2001 and 2000 in the accompanying consolidated statements of income for the years ended December 31, 2002, 2001 and 2000, respectively. Approximately $42.4 million, $32.4 million and $40.0 million of these respective amounts relates to the power projects accounted for under the equity method. The following table presents the Company's ownership interests at December 31, 2002, in these projects accounted for under the equity method:

          The Company exercises significant influence over the Facilities listed above through its representations on each Facilities' management committees or boards of control, which must approve all material transactions of these projects. See Note 5 for additional discussion regarding the Sterlington investment.

          The following table presents summarized combined financial data of the above projects accounted for under the equity method for the dates indicated (dollars in thousands):

          As a consequence of the event of default at the Sterlington Facility (see Note 8), the total borrowings for the Sterlington Facility of $386.5 million are callable and have been classified as a current liability in the above schedule as of December 31, 2002.

7.  LONG-TERM DEBT

          Long-term debt consisted of the following (dollars in thousands):

          Certain of the Facilities listed above incurred defaults or events of default during the year ended December 31, 2002, which are more fully described in Note 8. The current terms and conditions related to long-term debt prior to consideration of the defaults or events of default are described below. The Company's Southaven, Caledonia and Dominican Republic project subsidiaries continue to be in default of their notes payable and accordingly this debt is classified as a current liability in the accompanying consolidated balance sheets at December 31, 2002.

Rocky Mount Facility:

          The note payable to a financial institution consists of a senior loan that accrues interest at a fixed annual rate of 7.58%. Payment of principal and interest is due quarterly through December 2013.

Richmond Facility:

          The project debt includes $99.2 million of a note payable and $48.0 million of tax-exempt industrial development bonds (the "Richmond Bonds"). Interest on the notes payable accrues at an annual rate equal to the applicable LIBOR rate, as chosen by the Company, plus 1.13% through June 2003 (2.54% at December 31, 2002), 1.25% through June 2007, and 1.38% thereafter. Principal payments on the notes payable are due quarterly with interest payable the earlier of maturity of the applicable LIBOR term or quarterly through December 2007.

          The Richmond Bonds have been issued to support the purchase of certain pollution control and solid waste disposal equipment for the Facility. Principal and interest payments on the Richmond Bonds are supported by an irrevocable, direct-pay letter of credit provided under a credit facility under which the note payable was originally issued. The Richmond Bond letter of credit expires March 2010. The annual interest rate is the yield on the Richmond Bonds plus a 1.25% to 1.50% per annum fee (1.95% at December 31, 2002).

Cottage Grove and Whitewater Facilities:

          The project debt, excluding the fair market value adjustment consists of the following (dollars in thousands):

          Interest on these bonds is payable semi-annually on June 30 and December 30 of each year. Principal payments are due semi-annually through 2010 for the 2010 bonds and will be due semi-annually beginning on December 30, 2010, for the 2016 Bonds.

          On the date of acquisition of these Facilities, an adjustment in the amount of $22.2 million was recorded to reflect the Company's portion of the excess of the fair value of the fixed rate debt over its historical carrying value. This fair value adjustment, or debt premium, will be amortized to income over the life of the debt using the effective interest method.

          Cogentrix Mid-America, Inc. ("Mid-America"), a wholly-owned subsidiary of the Company, which holds the Company's interest in the Cottage Grove and Whitewater Facilities, has a credit agreement with a bank that currently has a $15.5 million letter of credit outstanding to support a portion of the debt service reserve requirements for the 2010 and 2016 bonds. This credit facility expires in December 2005 and as of December 31, 2002, no amounts are available under this credit facility. The total commitment to fund letters of credit under this credit facility is $17.7 million. Mid-America is required to contribute one-sixteenth of this amount to a letter of credit collateral account on a quarterly basis to be available to retire the letter of credit facility under the credit agreement upon its expiration in December 2005. As of December 31, 2002, $4.4 million has been funded to this letter of credit collateral account.

Jenks Facility:

          The proceeds from the project debt were used to construct an approximate 810-megawatt, combined-cycle, natural gas-fired generating Facility, which achieved commercial operations in February 2002 (the "Jenks Facility"). The construction borrowings converted to a term loan during June 2002 and will mature five years from the Facility's commercial operations date. The term loan agreement accrues interest at an annual rate equal to the applicable LIBOR rate, as chosen by the Company (2.68% at December 31, 2002), plus 1.30% per annum. No principal payments are due on the term loan for the first two years after the commercial operations date. All excess cash generated by the Facility during years three to five after the commercial operations date will be utilized to repay the outstanding principal on a quarterly basis. The loan facility also provides for an $8.0 million letter of credit to secure the project's obligation to pay debt service and a $11.7 million letter of credit to secure the Facility's obligations under its conversion services agreement.

Rathdrum Facility:

          The project debt consists of $69.7 million of term loans with banks, $49.0 million of term loans with a financial institution and a $5.0 million debt service reserve letter of credit. Proceeds from the borrowings were used to construct an approximate 270-megawatt, combined-cycle, natural gas-fired generating facility located in Rathdrum, Idaho, which achieved commercial operations in September 2001. Both term loans were converted from construction loans during October 2001. The financial institution loans accrue interest at 8.56% per annum with principal payments due quarterly commencing in December 2016 with a final maturity in December 2026. The bank loans accrue interest at the applicable LIBOR rate plus an applicable margin ranging from 1.25% to 2.25% (2.80% at December 31, 2002) with principal payments due quarterly through September 2019.

Dominican Republic Facility (see Note 8 for additional discussion):

          The project debt consists of the following (dollars in thousands):

          The export agency covered notes payable accrue interest at a fixed rate of interest ranging from 7.71% to 7.78% with principal payments due quarterly through 2011 for $14.1 million of the notes payable and quarterly through 2017 for the remaining notes payable. The notes payable to financial institutions accrue interest at a fixed weighted average rate of 9.28% with principal payments due quarterly beginning in 2012 and ending in 2017. The notes payable to banks accrue interest at the applicable LIBOR rate plus an applicable margin (weighted average of 3.37% at December 31, 2002) with principal payments due quarterly through 2013 for $72.2 million of the notes payable and quarterly through 2017 for the remaining notes payable. The equity contribution note payable was paid in full during 2002 under its original terms. The notes payable to financial institutions and $72.2 million of the notes payable to banks are covered by a political risk guarantee provided by the Inter-American Development Bank that protects these banks and financial institutions against the occurrence of certain events.

Southaven Facility (see Note 8 for additional discussion) :

          The original construction loan agreement provides up to $393.5 million in borrowings, a $10.0 million debt service reserve letter of credit and credit support letters of credit up to $60.0 million (the "Southaven Bank Loans"). Proceeds from the borrowings are being used to construct an approximate 810-megawatt, combined-cycle, natural gas-fired electric generating facility located near the city of Southaven, Mississippi (the "Southaven Facility"). Construction on the Southaven Facility began in May 2001, and commercial operations are expected to begin in mid-2003. The borrowings under the Southaven Bank Loans accrue interest at an annual rate equal to the applicable LIBOR rate, as chosen by the Company, plus 1.50% during the construction period (2.90% at December 31, 2002). The construction loans are required to be converted to term loans on January 1, 2004 and are due and payable in the event this does not occur. The term loans accrue interest per annum at an annual rate equal to the applicable LIBOR rate plus an applicable margin ranging from 1.63% to 1.88%. No principal payments are due on the term loans for the first eighteen months after conversion of the construction loans. All excess cash generated after this date will be utilized to repay the outstanding principal on a quarterly basis through the final maturity date which is four years after the conversion of the construction loans.

          During the construction period, the Southaven Facility's conversion services purchaser committed to provide up to $73.8 million in subordinated loans to the project upon the conversion services purchaser's event of default under the conversion services agreement. An event of default occurred on September 4, 2002, and the subordinated loan was activated. The subordinated loan borrowings were utilized to repay $73.8 million of the Southaven Bank Loans. This subordinated loan accrues interest at an annual rate equal to the applicable LIBOR rate plus 2.00% (2.88% at December 31, 2002). Interest compounds quarterly and is capitalized into the outstanding subordinated debt principal. The loan and accrued interest are payable in full on the earlier of September 2007 or after full repayment of the Southaven Bank Loans.

          The Company has committed to provide an equity contribution to this project of approximately $112.8 million. This equity contribution is supported by a letter of credit, which is provided under Cogentrix Energy's Corporate Credit Facility. The Company has made $33.0 million of these contributions through December 31, 2002. As a result of certain events of default during the year ended December 31, 2002, the Company was required to provide supplemental equity contribution commitments to the Southaven project which are required to be contributed upon the occurrence of certain events. These events are fully described in Note 8.

Caledonia Facility (see Note 8 for additional discussion):

          The construction loan agreement consists of a loan and reimbursement agreement which provides up to $500.0 million in borrowings and up to $60.0 million in credit support letters of credit. Proceeds from the borrowings are being used to construct an approximate 810-megawatt, combined-cycle, natural gas-fired electric generating facility located near Caledonia, Mississippi (the "Caledonia Facility"). Construction on the Facility began in July 2001, and commercial operations are expected to begin in mid-2003. The borrowings under the loan agreement accrue interest at an annual rate equal to the applicable LIBOR rate, as chosen by the Company, plus 2.75% (4.15% at December 31, 2002) during the construction period. The construction loans are required to convert to term loans before March 31, 2004 and are due and payable in the event conversion has not occurred before this date. The term loans accrue interest per annum at an annual rate equal to the applicable LIBOR rate plus 2.50% to 4.00%. No principal payments are due on the term loans for the first year after the commercial operations date. All excess cash generated by the Facility after this date will be utilized to repay the outstanding principal on a quarterly basis through the final maturity in July 2007.

CEA Credit Facility and Term Loan:

          Cogentrix Eastern America, Inc. ("Eastern America"), which holds interests in certain investments in unconsolidated power projects, amended an existing revolving credit facility during September 2002. The total outstanding borrowings of $60.0 million were extended with a new lender and converted to a term loan with a final maturity date of September 30, 2005. The term loans accrue interest at the applicable LIBOR rate plus 4.0% (5.79% at December 31, 2002) with principal payments due quarterly through September 30, 2005. Among other items, the Eastern America credit facility is secured by a pledge of the Eastern America capital stock and the capital stock of the project subsidiaries which hold the Company's investment in our Northampton and Logan projects as well as the dividends, distributions and other payments made to the Company by the Northampton, Logan, Indiantown and Carneys Point projects. The Eastern America credit facility requires Eastern America to continue to accumulate in escrow, the distributions received from four investments in unconsolidated power projects (Indiantown, Logan, Northampton and Carneys Point, collectively, the "Significant Affiliates") until the amounts accumulated in escrow reach $6.0 million before any distributions can be made to Eastern America (and ultimately, to Cogentrix Energy). If more than $6.0 million has been accumulated in escrow, such excess can be distributed to Eastern America prior to May 15, 2003, even if it could not otherwise be distributed if such restriction is solely a result of the Indiantown facility's inability to make distributions. At June 30, 2003, if certain conditions exist at certain of the Significant Affiliates which prevent those Significant Affiliates from making distributions to Eastern America, the entire $6.0 million held in escrow and, as long as any such conditions exist, any future distributions from those Significant Affiliates will be used to prepay debt. If at June 30, 2003, these conditions do not exist and the Significant Affiliates are able to make distributions to Eastern America, $3.0 million of the funds in escrow will be utilized to prepay outstanding borrowings with the remaining amount in escrow distributed to Eastern America and ultimately to Cogentrix Energy. In addition, if an event of default occurs under the project loan agreement for certain of Eastern America's project affiliates, a corresponding event of default would be triggered under the Eastern America credit facility.

Interest Rate Protection Agreements:

          The Company has entered into interest rate swap agreements to manage its interest rate risk on its variable-rate project financing debt. The agreements effectively change the interest rate on the portion of debt covered by the notional amounts from a weighted average variable rate of 2.87% at December 31, 2002, to a weighted average effective rate of 5.00%. Information related to these interest rate swap agreements is provided in the following table (dollars in thousands):

⁽¹⁾      The "variable rate receive" and "actual interest rate" are based on the interest rates in effect as of
          December 31, 2002. Interest rates in the future are likely to vary from those disclosed in the tables above.

Senior Notes:

          On March 15, 1994, Cogentrix Energy issued $100.0 million of registered, unsecured senior notes due 2004 (the "2004 Notes") in a public debt offering. The 2004 Notes were priced at par to yield 8.10%. In February 1994, Cogentrix Energy entered into a forward sale of ten-year U.S. Treasury Notes in order to protect against a possible increase in the general level of interest rates prior to the completion of the 2004 Notes offering. This hedge transaction resulted in the recognition of a gain of approximately $3.7 million that has been deferred and included as part of the 2004 Notes on the accompanying consolidated balance sheets. This deferred gain is being recognized over the term of the 2004 Notes, reducing the effective rate of interest on the 2004 Notes to 7.50%. During March 2001 and 2002, Cogentrix Energy redeemed $20.0 million each year of the 2004 Notes as required by the terms of the indenture under which these 2004 notes were issued. In addition to these scheduled redemptions, the Company repurchased an additional $14.4 million in face value of the 2004 Notes during December 2002 and an additional $5.9 million during January 2003. The early extinguishment of debt resulting from notes purchased in 2002, resulted in an extraordinary gain of approximately $2.9 million, net of tax and is included in the accompanying consolidated statements of income for the year ended December 31, 2002. The remaining $39.7 million of 2004 Notes are due to be repaid during March 2004.

          On October 20, 1998, Cogentrix Energy issued $220 million of registered, unsecured 8.75% senior notes due 2008 (the "2008 Notes"). These notes were issued at a discount resulting in an effective interest rate of approximately 8.82%. On November 25, 1998, the Company issued an additional $35 million of the 2008 Notes at a premium. In March 1998, in anticipation of the offering of the 2008 Notes, the Company entered into an interest rate hedge agreement to protect against a possible increase in the general level of interest rates. This hedge transaction resulted in the recognition of a loss of approximately $22.1 million which was deferred and is being recognized over the term of the 2008 Notes, resulting in an overall effective interest rate of approximately 9.59%.

          In September 2000, Cogentrix Energy issued an additional $100.0 million of its 2008 Notes. These notes were issued at a discount resulting in an effective rate of approximately 8.86%.

          In the event the lenders to the Corporate Credit Facility accelerate the outstanding obligations as a result of the default discussed in Note 2 or if the Corporate Credit Facility matures and is not repaid at its maturity in October 2003, this would create a cross-default under the indentures under which we issued the 2004 and 2008 Notes, and the senior note holders would have the ability to accelerate the $400.6 million of 2004 and 2008 Notes outstanding as of December 31, 2002 and demand immediate payment.

Corporate Credit Facility (see Note 2 for additional discussion):

          The Company has an agreement with a syndicate of banks that provides up to $250.0 million of revolving credit through October 2003 in the form of direct advances or the issuance of letters of credit (the "Corporate Credit Facility"). Borrowings bear interest at LIBOR plus an applicable margin based on the credit rating on Cogentrix Energy's 2004 and 2008 Notes (4.01% at December 31, 2002). Commitment fees related to the Corporate Credit Facility are 70.0 basis points per annum when greater than 50% of the available commitments are utilized and 80.0 basis points per annum when less than 50% of the available commitments are utilized, payable each quarter on the outstanding unused portion of the Corporate Credit Facility. As of December 31, 2002, the Company had used this credit facility to borrow approximately $93.7 million in loans and to issue approximately $132.1 million of letters of credit to support equity contribution commitments to certain projects and $21.7 million of letters of credit to support certain Facilities' obligations under certain of their operating agreements. As a result of the event of default discussed in Note 2, we are unable to borrow any additional funds or issue any additional letters of credit. In addition, we are unable to make any restricted payments, a category that includes shareholders dividends and loans to Cogentrix Energy shareholders or repay any other senior debt prior to its scheduled maturity. Since this event of default occurred, the lenders have provided the Company a limited waiver through May 31, 2003 that will allow the Company to continue to convert to borrowings, drawings under the outstanding letters of credit. Even though they have granted this limited waiver, the Company cannot provide assurances that the lenders to the Corporate Credit Facility will not choose nonetheless at any time to accelerate the obligations outstanding under the Corporate Credit Facility and demand immediate payment of all obligations outstanding.

Additional Terms and Conditions of Long-Term Debt:

          The project financing debt is substantially non-recourse to Cogentrix Energy. The project financing agreements of the Company's subsidiaries, the indentures for the 2004 and 2008 Senior Notes and the Corporate Credit Facility agreement contain certain covenants which, among other things, place limitations on the payment of dividends, limit additional indebtedness and restrict the sale of assets. The project financing agreements also require certain cash to be held with a trustee as security for future debt service payments. In addition, the Facilities, as well as the long-term contracts that support them, are pledged as collateral for the Company's obligations under the project financing agreements.

          The ability of the Company's subsidiaries to pay dividends and management fees periodically to Cogentrix Energy is subject to certain limitations in their respective financing documents. Such limitations generally require that: (i) debt service payments be current, (ii) debt service coverage ratios be met, (iii) all debt service and other reserve accounts be funded at required levels, and (iv) there be no default or event of default under the relevant credit documents. Dividends, when permitted, are declared and paid immediately to the Company at the end of such period.

          The Company's ability to pay dividends to its shareholders is restricted by certain covenants of the indentures for the 2004 and 2008 Senior Notes and the Corporate Credit Facility. These covenants did not restrict the Company's ability to declare a $13.5 million dividend on February 14, 2002 payable to shareholders of record on March 31, 2002, and to declare dividends of $10.3 million to the Company's shareholders for the year ended December 31, 2000.

          Future maturities of long-term debt at December 31, 2002, excluding the net unamortized premium on senior notes, the unamortized balance of the deferred gains and losses on hedge transactions and the unamortized fair market value adjustments, were as follows (dollars in thousands):

          *Included in the 2003 future maturities of long-term debt is the senior non-recourse project financing debt
            currently in default at our Dominican Republic, Southaven and Caledonia Facilities.

          Cash paid for interest excluding amounts capitalized in construction in progress on the Company's long-term debt amounted to $134.0 million, $97.3 million and $84.9 million for the years ended December 31, 2002, 2001 and 2000, respectively.

8.  PROJECT LEVEL DEFAULTS

          As discussed below, the Southaven, Caledonia, Sterlington and Dominican Republic Facilities continue to be in default of their project loan agreements. As a result, the Southaven, Caledonia and Dominican Republic Facilities' non-recourse project debt is callable and has been classified as a current liability in the accompanying consolidated balance sheets as of December 31, 2002. The Company accounts for the Sterlington project using the equity method of accounting and this Facility's assets and related liabilities, including long-term debt, are reflected net as an investment in unconsolidated affiliates in the accompanying consolidated balance sheets. The project lenders to these Facilities are not obligated to continue funding construction draws and have the right to exercise all remedies available to them under the applicable project loan agreement, including foreclosing upon and taking possession of all of the applicable project assets. Until the event of default under the applicable project loan agreements are cured, our project subsidiaries will be unable to make any distributions to Cogentrix Energy. These projects could remain in default for an extended period of time until the Company can cure the events of default, refinance the project loan agreements or in the case of the Southaven, Caledonia and Sterlington Facilities, provide a replacement conversion services or power purchaser. However, there can be no assurances that the Company will be able to enter into a replacement conversion services or power purchase agreement, refinance the project loan agreements or cure the events of default. The project lender to each Facility is able to satisfy this obligation with the applicable project's assets (total assets of approximately $1.2 billion as of December 31, 2002) only and cannot look to Cogentrix Energy or its other subsidiaries to satisfy this obligation. While these lenders do not have direct recourse to Cogentrix Energy, these defaults may still have important consequences for the Company's results of operations and liquidity, including, without limitation:

          Caledonia and Southaven Facility Customer Defaults - During August 2002, NEG, the guarantor of the conversion services purchaser at our Caledonia and Southaven Facilities, was downgraded below investment grade which created an event of default by NEG under each Facility's separate conversion services agreements (the "NEG Default"). This NEG Default created an event of default under these project subsidiaries' non-recourse loan agreements during February 2003. As a result, the applicable project lenders will not be obligated to continue funding construction draws and will have the right to exercise all remedies available to them under the applicable project loan agreement, including foreclosing upon and taking possession of all the applicable project assets. As a consequence of these events of default, the total senior borrowings for the Caledonia and Southaven Facilities of $395.1 million and $319.8 million, respectively, are callable and have been classified as a current liability on the consolidated balance sheets as of December 31, 2002.

          Sterlington Facility Customer Default - During July 2002, Dynegy Holdings, Inc. ("Dynegy"), the guarantor of the conversion services purchaser at our Sterlington Facility, was downgraded below investment grade creating a purchaser event of default under the Sterlington Facility's conversion service agreement and an event of default under the Sterlington Facility's non-recourse project loan agreements. During October 2002, the Company and the project lender amended the loan agreement requiring that all excess cash generated by the Facility be utilized to repay the outstanding borrowings under the Sterlington Facility's loan agreement on a quarterly basis. The project lenders have the right to exercise all remedies available to them under the project loan agreements including foreclosing upon and taking possession of all project assets. Dynegy continues to perform pursuant to the terms of the conversion services agreement and is current on its payments due to the Sterlington Facility. The Company accounts for this project using the equity method of accounting and this Facility's assets and related liabilities, including long-term debt, are reflected net as an investment in unconsolidated affiliates in the accompanying consolidated balance sheets. The Company's investment in this project was $2.6 million as of December 31, 2002.

          Dominican Republic Facility Customer Defaults - The Company's project subsidiary, which owns our Dominican Republic Facility that attained commercial operations during March 2002, notified the power purchaser Corporación Dominicana de Electricidad ("CDE"), on several occasions of events of default under the power purchase agreement based on CDE's failure to pay amounts due for the sale of electricity (the "Payment Defaults"). Under the terms of the project subsidiary's implementation agreement with the State of the Dominican Republic ("SDR"), which guarantees CDE's payment obligations, we demanded that the SDR pay certain of these amounts owed by CDE and, when the SDR failed to do so in the time allotted according to the implementation agreement, notified the SDR that they are in default of the implementation agreement for failing to pay this past due amount by CDE (the "SDR Defaults"). The Company exercised its rights under the power purchase agreement in October 2002 to suspend operation of this Facility on a continuing basis pending payment of the SDR Defaults. As of December 31, 2002, CDE owed the Company approximately $42.7 million in amounts due for the sale of capacity and electricity. Net of approximately $15.1 million in payments received subsequent to December 31, 2002, Payment Defaults and SDR Defaults currently exist related to $27.2 million of amounts invoiced prior to December 31, 2002. The lack of payment by CDE and the SDR created events of default under the Dominican Republic Facility's non-recourse project debt. The project lenders have the right to exercise all remedies available to them under the project loan agreements including foreclosing upon and taking possession of all project assets. As a consequence of these events, the total borrowings for the Dominican Republic Facility of $232.3 million are callable and have been classified as a current liability on the consolidated balance sheets as of December 31, 2002. As of December 31, 2002, the Company had net assets in the Dominican Republic Facility of approximately $51.9 million.

          The Company will continue to attempt to collect amounts past due from CDE or the SDR and will continue to exercise all of the rights and remedies we have available to us under the power purchase agreement, the implementation agreement and the SDR guarantee, including terminating the power purchase agreement. The termination of this agreement would require a termination payment by CDE or the SDR equal to the outstanding debt, invested capital by the project partners and other termination costs as defined in the power purchase agreement. Because the obligation is unsecured, we cannot give any assurances that the Company will be able to collect the termination amount from CDE or the SDR.

          Due to the ongoing payment defaults and the corresponding CDE and SDR defaults under the project subsidiary's non-recourse loan agreements, the project lenders have the right to delay the conversion of the outstanding borrowings from construction loans to term loans ("Conversion"). The failure of the project subsidiary to achieve Conversion on or before March 28, 2003 has resulted in an additional event of default under the project loan agreement.

          Logan Facility Default - On October 29, 2002, Anker Energy Corporation ("Anker"), the fuel supplier for the Logan Facility, filed for protection from its creditors under Chapter 11 of the United States Bankruptcy Code. Even though Anker continues to perform under the current agreement, this event constituted a default under the Logan Facility's project loan agreement. During January 2003, this default was deemed cured with the assumption of the fuel agreement by Anker during Anker's bankruptcy proceedings. The Company accounts for its 50% interest in the Logan Facility using the equity method of accounting and this Facility's assets and related liabilities, including long-term debt, are reflected net as an investment in unconsolidated affiliates in the accompanying consolidated balance sheets.

          Replacement EPC Contracts for Jenks, Sterlington and Southaven Projects and Related Defaults - National Energy Production Corporation or one of its affiliates ("NEPCO"), was formerly the construction contractor for these three new electric generating Facilities. On May 14, 2002 the project subsidiaries for the Sterlington and Southaven Facilities each signed an engineering, procurement and construction contract ("EPC Contract") with a subsidiary of SNC-Lavalin Group, Inc. ("SNC-Lavalin"), subject to the prior termination of, and to replace, their EPC Contracts with NEPCO. At the same time, the project subsidiary for our Jenks Facility signed a services contract (the "Services Contract") with an affiliate of SNC-Lavalin, subject to the prior termination of, and to replace, a contract with NEPCO to complete the punch list and clean up work for the Jenks Facility. These EPC Contracts and the Services Contract with SNC-Lavalin were deemed effective immediately following the termination of the NEPCO contracts for cause on May 17, 2002 prior to NEPCO filing for bankruptcy protection. Terminating the NEPCO contracts and executing the replacement EPC Contracts and Services Contracts with SNC-Lavalin for the Sterlington, Southaven and Jenks Facilities resulted in events of default under their non-recourse project loan agreements. We received waivers of the events of default from all of the project lenders during the year ended December 31, 2002.

          In connection with obtaining a waiver from the project lenders for the Southaven Facility, however, and in conjunction with certain other amendments to the Southaven Bank Loans, our project subsidiaries committed to provide additional equity and supplemental equity to the Southaven project. As of December 31, 2002, these equity contributions consisted of (i) $16.4 million of supplemental equity commitments that may be contributed in the event certain cost overruns are incurred to complete construction of the Southaven Facility and (ii) $35.7 million of supplemental equity commitments to fund any unpaid liquidated damages owed by NEPCO on the project. These aggregate equity contributions are supported by letters of credit issued under our Corporate Credit Facility.

          Insurance Coverage Defaults - The Company's project subsidiaries which own our Richmond, Rocky Mount, Dominican Republic, James River and Rathdrum Facilities incurred events of default during the year ended December 31, 2002 under their project loan agreements as a result of not being able to obtain the insurance coverage levels as required under the project loan agreements. The Company received waivers for these events of default. Subsequent to December 31, 2002, the Jenks Facility incurred a similar event of default which was waived during March 2003.

9.   LEASES

          The power purchase agreements at the Company's Cottage Grove and Whitewater Facilities have characteristics similar to leases in that the agreements confer to the Electric Customer the right to use specific property, plant and equipment. At the commercial operations date, the Facilities accounted for the power purchase agreements as "sales-type" capital leases in accordance with SFAS No. 13, "Accounting for Leases". The components of the net investment in the leases related to these "sales-type" capital leases were as follows (dollars in thousands):