DOCUMENTS INCORPORATED BY REFERENCE:  NONE

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. We sell the steam we produce 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 24 electric generating facilities in the United States and one in the Dominican Republic. Our 25 plants are designed to operate at a total production capability of approximately 5,294 megawatts. After taking into account our partial interests in the 18 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 25 electric generating facilities is approximately 2,896 megawatts. We currently operate 12 of our facilities, 10 of which we developed and constructed.

          We also have ownership interests in and will operate three facilities currently under construction in Louisiana and Mississippi. Once these facilities begin operation, we will have ownership interests in a total of 27 domestic - and one international - electric generating facilities that are designed with a total production capability of approximately 7,730 megawatts. Our net equity interest in the total production capability of those 28 facilities will be approximately 4,924 megawatts.

          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 Cogentrix Energy's "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 affil iate" or collectively as "project affiliates."

Our Strategy

          We intend to remain among the leaders in the independent power industry by developing and constructing or acquiring - entirely or in part - electric generating facilities in the United States and in foreign countries where the political climate is conducive to increased foreign investment.

          We have targeted two market segments for our future development and acquisition activities:

Industry Trends Creating Market Opportunities

     Increasing Competition in the Domestic Electric Generating Industry

          In response to increasing customer demand for access to low-cost electricity and enhanced services, new regulatory initiatives are currently being adopted or considered at both state and federal levels to increase competition in the domestic electric generating industry. We believe that these regulatory initiatives may lead to the transformation of the existing regulated, utility dominated market, that sells to a captive customer base and is based upon cost-of-service pricing, to a more competitive market in which end users may purchase electricity from a variety of suppliers, including non-utility generators, power marketers, public utilities and others at competitive prices. Our management believes that these market trends will create significant new business opportunities for us because we have demonstrated our ability to construct and operate efficient, low-cost electric generating facilities.

     Growing Market for Sale of Electric Generating Assets

          Regulatory initiatives to restructure the United States electric industry have led to the development of a growing market for the sale of electric generating assets principally by utilities, but also by independent power producers and industrial companies. In addition to regulatory pressure, the management of some utilities has decided, for strategic reasons, to sell some or all of their generating assets and to concentrate on the transmission and distribution segments of the power supply market. If this trend continues, it may create additional investment opportunities for us. In connection with acquiring - entirely or in part - any additional electric generating assets, we expect to reduce our exposure to electric market price risk by entering into contractual arrangements with fuel suppliers, utilities and/or power marketers under which they would assume some or all of the risks associated with fluctuations in fuel and energy prices.

     Expanded Options Resulting from Passage of the Energy Policy Act

          The passage of the Energy Policy Act in 1992 significantly expanded the options available to independent power producers, particularly with respect to siting a generating facility. Among other things, the Energy Policy Act enables independent power producers to obtain an order from the Federal Energy Regulatory Commission requiring an intermediary utility to give access to its transmission lines to transmit or "wheel" electric power from a generating facility to its utility purchaser. The availability of wholesale transmission "wheeling" could be an important aspect in the development of new projects. For example, we may be able to develop a project in one utility's service territory and "wheel" the electric power produced by the project through the transmission lines of that utility to a second utility or another wholesale purchaser. The Energy Policy Act also created a new class of generator - exempt wholesale generators - that, unlike qualify ing facilities, are not required to use alternative or renewable fuels or to have useful thermal energy output. Finally, the Energy Policy Act created another new class of utility-foreign utility companies-which may own and operate foreign utility assets without U.S. regulation consequences. See "Regulation - Energy Regulations" herein.

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 and power marketers. A facility's revenue from a power sales 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 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 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 agreements of substantially all of our facilities provide the electricity purchaser with the right to reduce or suspend their purchases 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 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 cove r 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 in which the electricity purchaser is responsible for providing the fuel, each of our facilities purchases 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 agreement. This matching is typically affected by having the fuel prices escalate as a function of the solid fuel index of the electricity purchaser. The matching is sometimes affected by contracting for scheduled increases in the variable payments under our power 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 or 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 and 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 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 our power and steam purchasers.

          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, distributions received by Cogentrix Energy from other projects may be used to satisfy these obligations. To the extent of these obligations, the lenders to a project may look to Cogentrix Energy and the distributions it receives fro m other projects for repayment. The aggregate contractual liability of Cogentrix Energy to its 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.

          In addition, Cogentrix, Inc., an indirect subsidiary of Cogentrix Energy, has guaranteed two project subsidiaries' obligations to the purchasing utility under two power sales agreements. Because these project subsidiaries' obligations do not by their terms stipulate a maximum dollar amount of liability, the aggregate amount of potential exposure under these guarantees cannot be quantified. Although we believe it is unlikely that Cogentrix, Inc. will have to honor either of these guarantees, if we or our subsidiary were required to satisfy all of these guarantees and other obligations at the same time, it could have a material adverse effect on our financial condition and results of operations.

          Two of our wholly-owned subsidiaries, which were formed to hold our interests in the electric generating facilities we acquired in 1999 and 1998, maintain their own credit agreements with banks. Distributions received by these subsidiaries from the project subsidiaries or project affiliates they own or hold an interest in may be used by these subsidiaries to satisfy any outstanding obligations under these revolving credit facilities.

          Our facilities are insured in accordance with covenants in each project's debt financing agreements. 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 twelve of our facilities. When we operate a facility, our project subsidiary 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 plants, 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 to pay these management fees is contingent upon the continuing compliance by the project subsidiary with covenants under its project financing agreements and may be subordinated to the payment of obligations under those agreements. We have earned and will continue to earn incentive compensation from our Hopewell facility, in which Cogentrix Energy holds a 50% general partnership interest and is, through a subsidiary, the managing general partner, if the facility achieves the contractually specified net income levels.

     Ash Removal

          Project subsidiaries owning seven 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 Under Construction

          We currently have three new "greenfield" electric generating facilities under construction. A brief description of each of these facilities follows with an estimate of the dates we expect them to commence commercial operations.

Facilities In Operation

          Our facilities described below rely on power sales agreements for the majority of their revenues. During the fiscal year ended December 31, 2001, two regulated utility customers accounted for approximately 55% of our consolidated revenues. 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 these utilities have senior, unsecured debt outstanding that nationally recognized credit rating agencies have rated investment grade. The Jenks, Oklahoma facility, the San Pedro, Dominican Republic facility and the Rathdrum, Idaho facility all recently achieved commercial operations. As a result of recent growth, our operations have become increasingly diverse with regard to both geography and fuel source and less dependent on any single project or customer.

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 began in February 2002 and 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 an annual capacity test.

     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 expiring in 2017. Our Richmond facility also provides steam to E. I. DuPont 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 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 is expected to provide approximately 295 megawatts of declared production capability to Corporación Dominicana de Electricidad under a power purchase agreement that expires 20 years after the entire facility is declared commercial. The first two units attained commercial operations during 2001 and the third unit attained commercial operations in March 2002. The contract capacity is subject to an adjustment based on a semi-annual capacity test. Corporación Dominicana de Electricidad 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 letter of credit to support its obligations under this power purchase agreement in conjunction with the entire facility being declared commercial. The State of the Dominican Republic has guaranteed the Corporación Dominicana de Elec tricidad's payment obligations to our project subsidiary through an implementation agreement unanimously ratified by the full Dominican Congress. See additional discussion under "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Other Significant Events" regarding this guarantee.

          Our project subsidiary is required to pay liquidated damages to Corporación Dominicana de Electricidad 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. ""PG&E National Energy Group, Inc. ("PG&E"), 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 production capability to Florida Power & Light Company under a power sales agreement that expires in 2025. Fixed 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 f aith, 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 PG&E provides operation and maintenance services for the Indiantown facility pursuant to an operating agreement that expires in 2025. PG&E manages and administers the business of the partnership that owns the facility pursuant to a management service agreement that expires in 2029.

     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 Tomen Power Corporation 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 ("Standard & Poor's"), Moody's Investors Service, Inc. ("Moody's") 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 preclude d 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 O&M 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 Tomen Power Corporation 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 O&M 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 began in September 2001 and 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 Portsmouth facility also sells process steam to BASF Corporation and Celanese Chemical, Inc.

          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.

     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 agreemen t is made.

          If a disallowance event occurs through 2002, then 25% of cash flow from the facility must be deposited to the regulatory disallowance reserve account until the balance of such account is equal to the amount required to be funded. 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 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 two stoker coal-fired cogeneration plants in Roxboro and Southport, North Carolina, that are owned by another wholly-owned project subsidiary of Cogentrix Energy.

          The Roxboro and Southport facilities sell electricity under separate power sales agreements with Carolina Power & Light, each of which expires in December 2002. The 60-megawatt Roxboro facility may operate at a declared production capability of up to 56 megawatts and the 120-megawatt Southport facility may operate at a declared production capability of up to 107 megawatts. Cogentrix, Inc., has guaranteed the performance of our project subsidiary under the power sales agreements. Collins & Aikman Corporation purchases process steam for its textile manufacturing facility from the Roxboro facility and ArcherDaniels-Midland Company purchases steam for its pharmaceutical and chemical manufacturing company from the Southport facility.

          Each of the power sales agreements provide that in the event our project subsidiary desires to terminate the power sales agreement or abandons the Roxboro or Southport facility, our project subsidiary must pay the utility a termination charge. Such termination charge will be equal to the sum of the following:

     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 facility. The 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 in 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 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. PG&E 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 PG&E 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, which began operation in September 1994, provides up to 203 megawatts of declared production capability to Atlantic City Electric Company 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. The Logan facility sells steam to Solutia, Inc.

          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.

          An affiliate of PG&E provides operation and maintenance services for the Logan facility pursuant to an operation and maintenance agreement with an initial term expiring in 2004. PG&E provides management services pursuant to a management services agreement that expires in 2027.

     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. 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. 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 consolidated revenue for the fiscal years ended December 31, 2001, 2000 and 1999 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.

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 envir onmental 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.

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 Federal Energy Regulatory Commission ("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 further 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. Therefore, all of our subsidiaries that own or operate power plants are exempt from regulation under PUHCA. 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, most of the projects currently being constructed by our subsidiaries will qualify as EWGs with market-based rate authority. Pursuant to the FPA, our power marketing subsidiary has also filed its wholesale electric power rates with FERC and obtained authorization to sell electric power at market-based rates.

          A seller with market-based rate authorization from FERC may negotiate any rate for wholesale power sales or may sell power at wholesale at rates set by supply and demand in the marketplace. Market-based rate authorizations generally are predicated on FERC's finding that the seller lacks market power. FERC has recently changed its standards for determining whether any seller has market power, and is implementing this change for all new sellers seeking market-based rates as well as for any existing seller updating its market-based rate authorization or filing a change in its rates. Although FERC's new standards are more stringent than the prior standards, we believe that all of our subsidiaries with market-based rates can meet the new FERC test, and may therefore continue to charge market-based rates for sales from their facilities.

     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 t o 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 in this session of Congress, 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 repeal of PUHCA.

          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 will 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.

          Retail access programs may provide Cogentrix with additional opportunities to provide power from our projects to industrial users or power marketers.

     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.

          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 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. Management believes that Cogentrix would have a meritorious defense to any action brought by the EPA relating to any of its facilities. 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. This inspection is scheduled for April 23, 2002.

          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. These facilities must 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 2002 deadline for this upgrade. We expect we will need to install 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 may need, or decide 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 upo n 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.

          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 certa in 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, 2001, we employed 562 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, which we purchased in October 2001. Previously, we leased the building from a partnership comprised of four shareholders of Cogentrix Energy. See "Certain Relationships and Related Transactions--Leases and Real Property Transactions."

          We also lease office space in Prince George, Virginia, Wilmington, Delaware and Portland, Oregon.

          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

     Claims and Litigation

          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 1997-1998 in various construction projects. Management cannot currently estimate the range of possible loss, if any, we will ultimately bear as a result of these claims. However, our management believes - based on its 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 or on Cogentrix Energy's ability to generate sufficient cash flow to service its outstanding debt.

          In addition to the litigation described above, we experience other routine litigation in the normal course of business. Our management is of the opinion that none of this routine litigation will 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, 2001, 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, 2001 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 "Management's Discussion and Analysis of Financial Condition and Results of Operations" includes statements concerning certain trends and other forward-looking information affecting or relating to Cogentrix which 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 which could cause the actual results to differ materially from the forward-looking statements. See cautionary statements appearing under 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 Our Financial Condition and Results of Operations

     Termination or Modification of Certain of our Power Sales Agreements

          The power sales agreements at three of our project subsidiaries terminated during the years ended December 31, 2001 and 2000. The power sales agreements at two of our other project subsidiaries will terminate in 2002 and the power sales agreements at two of our other project subsidiaries provide for a significant reduction in fixed payments received under such agreements after December 2002. Accordingly, revenues recognized by us under these power sales agreements have been or will be eliminated or significantly reduced. Our management believes, however, that our remaining project subsidiaries and project affiliates will generate sufficient cash flow to allow them to pay management fees and dividends to Cogentrix Energy periodically in sufficient amounts to allow Cogentrix Energy to pay all required debt service on our outstanding senior notes and our corporate credit facility, fund a significant portion of our development activities and permit Cogentrix Energy to meet its other obligations.

     Legislative Proposals to Restructure the Electric Generating Industry

          The domestic electric generating industry is currently going through a period of significant change as many states are implementing or considering regulatory initiatives designed to increase competition. We cannot predict the final form or timing of the proposed restructurings and the impact, if any, that such restructurings would have on our existing business or consolidated results of operations. Because these restructuring proposals have generally included a grandfathering provision for contracts entered into prior to repeal of existing legislation, we believe that any such restructuring would not have a material adverse effect on our power sales agreements. Accordingly, we believe that our existing business and results of consolidated operations would not be materially adversely affected, although there can be no assurance in this regard.

     Facilities Achieving Commercial Operations

          Our growth has substantially increased our electric production capability. The Rathdrum facility achieved commercial operations during 2001 resulting in the recognition of additional lease revenue (for the capacity payments under its conversion services agreement that are accounted for as an operating lease) and energy revenue. In addition, a portion of the San Pedro facility also achieved commercial operations during 2001 with the remaining portion achieving commercial operations in March 2002 resulting in the recognition of additional energy and capacity revenue. These facilities were financed with debt and as a result, have impacted the interest expense reported in our results of operations. Our facilities under construction at December 31, 2001 will not have a significant impact on our results of operations until they begin commercial operations, at which time, we will experience an increase in operating revenues, operating expenses and i nterest expense. The Jenks facility achieved commercial operations during February 2002.

Results of Operations

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

     Operating Revenues

          Total operating revenues 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 due to 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.

Year Ended December 31, 2000 as compared to Year Ended December 31, 1999

     Operating Revenues

          Total operating revenues increased 23.1% to $551.1 million for the year ended December 31, 2000 as compared to $447.6 million for the year ended December 31, 1999 as a result of the following:

     Operating Costs

          Total operating expenses increased 32.3% to $258.2 million for the year ended December 31, 2000 as compared to $195.1 million for the year ended December 31, 1999 as a result of the following:

     General, Administrative and Development Expenses

          General, administrative and development expenses increased 8.5% to $42.3 million for the year ended December 31, 2000 as compared to $39.0 million for the year ended December 31, 1999. This increase is primarily due to an increase in compensation expense related to an increase in the number of corporate employees and an increase in incentive compensation expense related to our increased profitability. The increase in general, administrative and development expenses was partially offset by a decrease in information system consulting costs in 2000 resulting from the implementation of various new core business systems in 1999.

     Depreciation and Amortization

          Depreciation and amortization increased approximately $7.0 million primarily from the commencement of commercial operations of the Batesville facility.

     Interest Expense

          Interest expense increased 10.7% to $105.2 million for the year ended December 31, 2000 as compared to $95.0 million for the year ended December 31, 1999. The increase in interest expense is primarily related to incremental interest expense from the inclusion of long-term debt from the Batesville facility which began commercial operations in August 2000, additional borrowings of approximately $25.2 million at our Richmond facility in June 2000, and the issuance of an additional $100.0 million of our 8.75% senior notes due 2008 in September 2000. The increase in interest expense was offset by a reduction in interest expense at several of our project subsidiaries due to scheduled repayments and retirements of outstanding project financing debt.

     Other Expense, Net

          Other expense, net, increased primarily as a result of a charge to reduce the carrying value of a note receivable to its estimated net realizable value, as a result of uncertainties with respect to collectibility.

Liquidity and Capital Resources

     Consolidated Information

          The primary components of cash flows from operations for the year ended December 31, 2001, were as follows (dollars in millions):

          Total cash flows from operations of $99.9 million, proceeds from borrowings of $702.1 million, additional investments from minority interests of $10.2 million and proceeds from sales of project interests of $119.8 million were used primarily to (dollars in millions):

          As of December 31, 2001, we had long-term debt (including the current portion thereof) of approximately $2.2 billion. With the exception of the $435.0 million of senior notes outstanding as of December 31, 2001, substantially all such indebtedness is project financing debt, the majority of which is non-recourse to Cogentrix Energy. The project financing debt generally requires the extensions of credit to be repaid solely from the project's revenues and provide that the repayment of the extensions of credit (and interest thereon) is secured solely by the physical assets, agreements, cash flow and, in certain cases, the capital stock of or the partnership or membership interest in that project subsidiary. Future annual maturities of long-term debt range from $62.2 million to $167.3 million in the five-year period ending December 31, 2006. We believe that our project subsidiaries and project affiliates will generate sufficient cash flow to pay all required debt service on their project financing debt and to allow them to pay management fees, dividends or distributions to Cogentrix Energy periodically in sufficient amounts to allow Cogentrix Energy to pay all required debt service, fund a significant portion of its development activities and meet its other obligations.

          The ability of our project subsidiaries and project affiliates to pay dividends, distributions and management fees periodically to Cogentrix Energy is subject to certain limitations in our respective financing documents. Such limitations generally require that: (1) debt service payments be current, (2) debt service coverage ratios be met, (3) all debt service and other reserve accounts be funded at required levels and (4) there be no default or event 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. Management does not believe that such restrictions or limitations will adversely affect Cogentrix Energy's ability to meet its debt obligations.

     Credit Facilities

          The corporate credit facility, which expires in October 2003, provides direct advances to, or the issuance of letters of credit for, our benefit in an amount up to $250.0 million. At December 31, 2001, we had utilized approximately $199.6 million of the credit available primarily for letters of credit issued in connection with projects we have under construction or recently completed construction of in Oklahoma, Mississippi and the Dominican Republic and to support fuel purchases at our Dominican Republic facility. The balance of the commitments under the corporate credit facility is available, subject to any limitations imposed by the covenants contained therein and in the indentures, to be drawn upon by us to repay other outstanding indebtedness or for general corporate purposes, including equity investments in new projects or acquisitions of existing electric generating facilities or those under development.

          Two of our wholly-owned subsidiaries, Cogentrix Eastern America, Inc. ("Eastern America") and Cogentrix Mid-America, Inc. ("Mid-America"), formed to hold interests in electric generating facilities acquired in 1999 and 1998, maintain credit agreements with banks with $60.0 million in outstanding borrowings and $15.0 million in outstanding letters of credit, respectively, that are non-recourse to Cogentrix Energy. As of December 31, 2001, there are no amounts available under these facilities. The Eastern America facility matures in September 2002 and, the Mid-America facility matures in December 2005. Management intends to refinance the Eastern America credit agreement prior to September 2002. However, there are no assurances that Eastern America will be able to refinance the credit agreement on economically attractive terms.

     Facility Construction

          We currently have three electric generating facilities under construction and have substantially completed construction on two other facilities. The construction of each facility was or is being funded under each project subsidiary's separate financing agreements and equity contribution commitments by Cogentrix and/or our partners. Our equity contribution commitments for the Southaven, Dominican Republic and Jenks facilities are supported by letters of credit provided under Cogentrix Energy's corporate credit facility. Substantially all of these equity commitments will be contributed no later than the mandatory equity contribution date shown in the table below for each project utilizing corporate cash balances or advances under the corporate credit facility. Summarized information regarding each of the facilities follows (dollars in millions):

(a)      For a discussion regarding our ownership percentage in the Caledonia facility, see "Business - Facilities Under Construction".

          Any project 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. 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.

          The project subsidiaries and project affiliate for our facilities under construction are required to pay delay liquidated damages or provide replacement power under the power sales agreements in the event we do not achieve commercial operations by a designated start date. The contractor constructing our facilities is, however, required to pay us liquidated damages in the event construction is not completed by a designated start date which is consistent with the target commercial operations date under the respective power sales agreements. For information about the ability of the construction contractor for four of our generating facilities that are either under construction or recently completed to perform its obligations under the construction contracts, including its obligation to pay any delay liquidated damages, see the discussion immediately below under the heading "Impact of Enron Bankruptcy Filing on Our Facilities Under Construction."

          During December 2001, we drew $53,020,000 under letters of credit provided on behalf of the construction contractor constructing our Jenks facility as a result of the contractor not meeting a completion deadline under the construction contract. A portion of these funds was utilized to pay for delay liquidated damages owed to the Jenks facility by the contractor as the result of late completion of the facility. The remaining funds may be used to pay for any other obligations owed by the contractor under the construction contract.

     Impact of Enron Bankruptcy Filing on Our Facilities Under Construction

          National Energy Production Corporation ("NEPCO"), a wholly-owned subsidiary of Enron Corporation ("Enron"), is the construction contractor for four of our new electric generating facilities. One of them, our generating facility in Jenks, Oklahoma, achieved commercial operations during February 2002. The three other generating facilities are located in Ouachita, Louisiana, Southaven, Mississippi and Caledonia, Mississippi. At each of these facilities, we have a fixed-price, date-certain, turnkey engineering, procurement and construction contract ("EPC Contract") with NEPCO. Enron has guaranteed NEPCO's payment and performance obligations under these EPC Contracts.

          In December 2001, Enron and certain of its subsidiaries filed for protection from their creditors under Chapter 11 of the United States Bankruptcy Code. NEPCO was not one of the subsidiaries included in Enron's filing, but NEPCO's payroll, cash management and certain other support functions were integrated with Enron's, and Enron swept approximately $28.0 million of construction progress payments we had made to NEPCO under these EPC Contracts before NEPCO could apply those payments to construction costs on our projects. NEPCO has been working with its employees, vendors, subcontractors and customers since then to ensure that NEPCO can continue to meet its own working capital needs and its obligations to others, including its obligations to us under these EPC Contracts. Although our facility in Ouachita, Louisiana will not be completed as scheduled in June 2002, we believe the liquidated damages NEPCO will be obligated to pay as a result of t he anticipated two to three month delay in completing the project as well as any other project construction cost overruns will not exceed the amounts of the letters of credit Enron posted to secure NEPCO's payment and performance obligations under the EPC Contract for this facility. The target completion dates for our Southaven and Caledonia projects are each more than 14 months away, and, at present, we have no reason to believe that these projects will not be completed as scheduled.

          To address the immediate consequences of the Enron bankruptcy filing on the construction of these facilities, we entered into amendments to our EPC Contracts with NEPCO. Under the amended contracts, NEPCO has assigned all of the critical subcontracts and purchase orders for these facilities to our project subsidiaries and project affiliate to ensure that NEPCO's subcontractors and vendors will continue to meet their performance obligations. These assignments will allow our project subsidiaries and project affiliate to control the payment of project specific costs by making them directly to NEPCO's subcontractors and vendors. These assignments also include the assignment of contracts NEPCO had with the major equipment suppliers for each project.

          Because we had to respond rapidly to mitigate the impact of Enron's bankruptcy filing, we did not obtain consents from the project lenders for these facilities prior to amending the EPC Contracts with NEPCO. Consequently, the amendments and the Enron bankruptcy filing were defaults or events of default under the loan agreements for each project. The project lenders have subsequently agreed to amend the loan agreements for these projects, waive the defaults or events of default thereunder and provide the necessary consents. Before doing so, however, they required our project subsidiaries developing the Southaven and Caledonia facilities to provide additional support and required Cogentrix Energy to provide certain guarantees of such project subsidiaries' performance as well as certain indemnities. They also required Cogentrix Energy to post letters of credit providing security for a portion of these guarantees.

          Cogentrix Energy has posted two letters of credit to support the Southaven project. The first is a $14.4 million Letter of Credit that secures our project subsidiaries' obligations to make additional equity contributions to the project to cover liquidated damages or other obligations payable by NEPCO as well as any project cost overruns whether or not they are payable by NEPCO. This letter of credit was posted prior to December 31, 2001, and is included in the $112.8 million total Cogentrix equity commitment in the table directly above under the heading "Facility Construction." The second is a $24.7 million letter of credit that secures our project subsidiaries' obligation to make additional equity contributions to the project to cover any liquidated damages payable by NEPCO that are not paid in a timely manner. Our project subsidiary developing the Southaven facility committed to provide a supplemental equity contribution to the Southaven proje ct if additional funds are needed to pay any unpaid obligations of NEPCO under the EPC Contract or cover certain cost overruns. The maximum amount of this contingent supplemental equity contribution is currently $10.9 million. This contingent supplemental equity contribution is adjusted on December 31, 2002 to $50.9 million less the aggregate amount of interest savings during construction or other contingency cost savings on the Southaven facility. Only $10.0 million of the $50.9 million supplemental equity commitment can be utilized to cover general project cost overruns. Cogentrix Energy has guaranteed the project subsidiary's commitment to provide a supplemental equity contribution to the Southaven project. This guarantee is unsecured at present, but Cogentrix Energy has agreed to secure its guarantee with a letter of credit if 'its senior unsecured notes are rated below investment grade by both Moody's and Standard & Poor's.

          The project subsidiary developing our Caledonia project committed to provide a supplemental equity contribution of up to $20 million to the Caledonia project to cover expenses associated with the EPC Contract with NEPCO for this facility that are in excess of the original budgeted construction cost of the project and any liquidated damages that NEPCO is obligated but unable to pay. Cogentrix Energy has provided an unsecured guarantee for the project subsidiary's performance of this commitment. If we subsequently replace NEPCO as the construction contractor for this project, our project subsidiary will be released from its obligation to provide a $20 million supplemental equity contribution unless, but only to the extent that, additional amounts are required to cover material rework of work on the project previously performed by NEPCO or its subcontractors.

          If NEPCO or any of its principal subcontractors or vendors fails to perform, fails to pay liquidated damages, becomes insolvent or files for bankruptcy protection, we could encounter significant delays and cost overruns in completing these facilities. And to ensure they are completed, Cogentrix Energy could be required to make supplemental equity contributions on behalf of the project subsidiaries, post letters of credit or otherwise provide additional support to the projects. Delay in completing the projects could result in our project subsidiaries or project affiliate becoming obligated to pay liquidated damages under the conversion services agreements for these facilities as well as delays in the affected project subsidiaries' or project affiliate's ability to generate cash flow, comply with covenants in their project loan agreements and pay management fees and dividends to Cogentrix Energy. We are continuing to assess NEPCO's ability to p erform its obligations under these EPC Contracts and may need from time to time take additional measures we deem prudent to avoid or reduce the length of delays NEPCO may encounter in completing these facilities on schedule.

     Project Level Default at Ouachita Facility

          The letter of credit posted on behalf of the construction contractor for the Ouachita facility to secure the contractor's payment and performance obligations was not issued in the name of the security agent for the project lenders as required by the non-recourse loan agreements for this project affiliate. Until this event of default is cured, the project lenders are not obligated to continue funding construction draws. Consequently, our partner or we may have to fund construction costs temporarily until the event of default is cured to avoid interruption in the construction of the Ouachita facility. If the event of default is not cured by May 1, 2002, we and our partner may also have to post a $10.0 million letter of credit for the benefit of the power purchaser to support our project affiliate's obligations under its conversion services agreement.

          We expect this event of default will be cured and that the Ouachita facility will be completed by and will commence commercial operations in August 2002. The project loan agreements currently require the facility to be completed not later than June 1, 2002, however, and the non-recourse construction loans for the facility become due on June 1, 2002 if the facility is not substantially completed by that date. We intend to either extend the maturity date or to refinance the construction loans for a term that ends after the expected completion date of the facility. We may not be able to extend the maturity date of the non-recourse project loans, however, or to refinance them on economically attractive terms.

     Other Significant Events

          During February 2001, we sold a 50% membership interest in our Ouachita facility. In exchange, we received $48.3 million in cash and were relieved of our original equity commitment up to approximately $56.3 million that had been supported by a letter of credit issued under our corporate credit facility. We have retained a 50% ownership of this facility and will manage and operate this facility upon commercial operations. As part of the purchase of the 50% membership interest, MEP-I, LLC assumed a proportionate share of the net liabilities of this project affiliate, and we recorded a gain of approximately $50.3 million, net of transaction costs related to this sale.

          During March 2001, we sold our entire 51.4% interest in the Batesville facility to NRG Energy, Inc. for $64.0 million in cash. In connection with the sale, we also assigned our responsibility for the operation and maintenance of the Batesville facility to an indirect subsidiary of NRG Energy, Inc. We recorded a gain of approximately $8.5 million, net of transaction costs related to this sale.

          During 2001, we made an equity contribution of approximately $14.5 million to our Rathdrum, Idaho facility that achieved commercial operations during September 2001. This equity contribution commitment had previously been supported with a letter of credit under our corporate credit facility

          During September 2001, we prepaid in full approximately $20.4 million of project subsidiary debt at our Portsmouth, Virginia facility.

          We currently have commitments with turbine and other equipment suppliers to purchase a specified number of turbines and heat recovery steam generators with specified delivery dates. We made approximately $93.6 million in non-refundable deposits related to these commitments during the year ended December 31, 2001. We expect to make additional progress payments of $84.0 million in 2002.

          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. In addition, under the terms of the indentures for our two issues of senior notes and our corporate credit facility, our ability to pay dividends and make other distributions to our shareholders is restricted.

          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. Sixty million dollars of these notes remain outstanding.

          In March 2002, the project subsidiary which owns our Dominican Republic facility that attained commercial operations during 2002 notified the power purchaser, Corporación Dominicana de Electricidad ("CDE"), of an event of default under the power purchase agreement based on CDE's failure to pay amounts due for the sale of electricity. CDE has subsequently paid approximately $1.8 million of the amounts past due leaving approximately $14.2 million still past due. Under the terms of the project subsidiary's implementation agreement with the State of the Dominican Republic, which guarantees CDE's payment obligations, we have demanded that the State of the Dominican Republic pay all amounts past due owed by CDE. We will continue to attempt to collect amounts past due from CDE or the State of the Dominican Republic and will continue to exercise all of the rights and remedies we have available to us under the power purchase agreement, the implemen tation agreement and the Dominican State Guarantee.

          We are presently evaluating, with the assistance of investment bankers, strategic alternatives in order to maximize shareholder value. The alternatives we are considering may include a sale of all or a portion of the Company's stock or assets. There can be no assurance, however, that any strategic transaction will be agreed upon or effected.

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 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 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 power purchaser is typically obligated to supply and pay for fuel necessary to generate the electrical output expected to be dispatched by the customer.

          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. We have sought to reduce this risk by entering into contracts with creditworthy organizations.

     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, interest rate caps 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, 2001. 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, 2001. Future interest rates are likely to vary from those disclosed in the table.

          The following tables contain information as of December 31, 2001, regarding interest rate swap and interest rate cap 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, 2001, was $114,309,744. 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 3.17% to a weighted average effective rate of 6.86% at December 31, 2001.

(1)     The "variable rate receive" and "actual interest rate" are based on the interest rates in effect as of December 31,
          2001. Interest rates in the future are likely to vary from those disclosed in the tables above.

          During March 2002, one of our project subsidiaries entered into a swap agreement covering approximately $224.9 million of project debt. The agreement calls for our project subsidiary to pay a fixed rate of interest during the term of the agreement which expires in August 2003.

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.

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

TO COGENTRIX ENERGY, INC.:

          We have audited the accompanying consolidated balance sheets of Cogentrix Energy, Inc. (a North Carolina corporation) and subsidiary companies as of December 31, 2001 and 2000, and the related consolidated statements of income, changes in shareholders' equity and cash flows for each of the three years ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

          We conducted our audits in accordance with auditing standards generally accepted in the United States. 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 audits provide a reasonable basis for our opinion.

          In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Cogentrix Energy, Inc. and subsidiary companies as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.

          As explained in Note 2 to the consolidated financial statements, effective January 1, 2001, the Company changed its method of accounting for derivative instruments and hedging activities.

          Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed in the index of financial statements is presented for purposes of complying with the Securities and Exchange Commission's rules and is not a required part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in our audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.

ARTHUR ANDERSEN LLP          

Charlotte, North Carolina,
February 7, 2002 (except with respect
to the matters discussed in the
first paragraph of Note 7 as to which
the date is April 12, 2002)

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

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, 2001, 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 5,294 megawatts. After taking into account the partial interests in the 18 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 2,896 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, 2001, the Company owned or had interests in three Facilities under construction in Louisiana and Mississippi with an expected aggregate production capability of 2,436 megawatts. After taking into account a 50% interest in one of these Facilities, the Company's net ownership interest in the total expected production capability of these Facilities under construction is approximately 2,028 megawatts (see Note 10 for additional discussion regarding our ownership interest in the Caledonia Facility).

2.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

          Principles of Consolidation and Basis of Presentation - The accompanying consolidated financial statements include the accounts of Cogentrix Energy and its subsidiary companies. Wholly-owned and majority owned subsidiaries, including 50% owned entities in which the Company has effective control through its designation as the managing partner of this project, are consolidated. Less-than-majority-owned subsidiaries 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 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. As of December 31, 2001 and 2000, fuel and spare parts inventories were comprised of the following (dollars in thousands):

          Coal and fuel inventories at certain Facilities are recorded at last-in, first-out ("LIFO") cost of $18,188,000 and $4,316,000 at December 31, 2001 and 2000, respectively, with the remaining Facilities' coal inventories recorded at first-in, first-out ("FIFO") cost. The cost of coal and fuel inventories recorded on a LIFO basis was approximately $989,000 higher and $181,000 lower than the cost of these inventories on a FIFO basis as of December 31, 2001 and 2000, respectively. Spare parts inventories are recorded at average cost. Spare part inventories of $22,346,000 and $25,068,000 as of December 31, 2001 and 2000, 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.

          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, 2001, 2000 and 1999 was $34,561,000, $43,248,000 and $37,876,000, 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 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, 2001, 2000 and 1999, the Company capitalized $54,917,000, $26,632,000 and $1,812,000, 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 affiliates include investments in unconsolidated 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, permits 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, 2001 and 2000 were $9,679,000 and $9,205,000, respectively.

          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 agreements. Significant portions of the Company's revenues have been derived from certain electric utility customers. Two customers accounted for 43% and 12% of revenues in the year ended December 31, 2001, 43% and 15% of revenues in the year ended December 31, 2000 and 47% and 17% of revenues in the year ended December 31, 1999.
          
          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.

          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 primarily engages in interest rate swap agreements, under which the Company agrees to pay fixed rates of interest. The differ ential 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 $4,386,000, 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 year ended December 31, 2001, the Company recorded approximately $3,734,000, net of deferred taxes, in net deferred losses related to its interest rate swaps in other comprehensive income. The Company currently has interest rate swaps th at mature from 2002 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. 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.

          New Accounting Pronouncements - In June 2001, the FASB issued 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 will adopt the provisions of SFAS No. 142 effective January 1, 2002, as required, and apply the provi sions of SFAS No. 142 to all goodwill and other intangible assets recognized in the consolidated financial statements. SFAS No. 142 requires a transition impairment test of goodwill and other intangibles in conjunction with the initial application. Any resulting impairment loss will be reflected as a change in accounting principle. As of December 31, 2001, the Company had unamortized goodwill and unamortized net purchase price premium in unconsolidated power projects totaling $153.1 million. Amortization expense related to these items was $6,360,000, $6,633,000 and $5,314,000 for the years ended December 31, 2001, 2000 and 1999, respectively. Management has prepared a transition test of its unamortized goodwill and does not expect SFAS No. 142 to have a material impact on the carrying value of these intangible assets. In addition, management continues to assess the carrying value of the net purchase price premium in accordance with APB No. 18 and believes that these intangible assets are recoverable in all material respects. Management has determined that its unamortized goodwill and net purchase price premium have indefinite useful lives and will eliminate the amortization of these assets beginning in 2002.

          In August 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 October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." 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 provisions of this statement are effective for the Company on January 1, 2002. 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. In management's opinion, at December 31, 2001, the carrying value of th e Company's long-lived assets, including goodwill, was recoverable in all material aspects. Management believes the adoption of this pronouncement is immaterial to the accompanying consolidated financial statements.

          Reclassifications - Certain amounts included in the accompanying consolidated financial statements for the years ended December 31, 2000 and 1999, have been reclassified from their original presentation to conform with the presentation for the year ended December 31, 2001.

3.  ACQUISITIONS

          During 1999, the Company purchased an additional 40% ownership interest in the Indiantown Facility, one of the Company's investments in unconsolidated power projects. The purchase method of accounting was used to record this acquisition. The aggregate purchase price was approximately $76.6 million and was acquired in a three-phase transaction. The purchase resulted in a premium of approximately $38.0 million which is being amortized over the remaining term of the power purchase agreement which expires in December 2025. The Company currently has a 50% ownership interest in the Indiantown Facility and the investment is accounted for using the equity method.

          During February 2000, the Company purchased additional 1% interests in the Logan and Northampton Facilities, two of the Company's investments in unconsolidated power projects. The purchase method of accounting was used to record this acquisition. The Company paid approximately $1.7 million for these additional interests. The Company will continue to account for its 50% interest in the Logan and Northampton Facilities using the equity method.

          The following unaudited pro forma consolidated results for the Company for the year ended December 31, 1999, give effect to these acquisitions as if this transaction had occurred on January 1, 1999, (dollars in thousands, except per share amount):

          The pro forma results have been prepared for comparative purposes only and are not necessarily indicative of the actual results of operations had the acquisitions taken place as of January 1, 1999.

4.    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 Ouachita Power, LLC ("Ouachita Power"), sold a 50% membership interest in Ouachita Power (the "Ouachita Sale") to an indirect subsidiary of General Electric Capital Corporation ("GECC"). Ouachita Power is constructing an approximate 816-megawatt, combined-cycle, natural gas-fired electric generating facility near the city of Sterlington, Louisiana (the "Ouachita 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 Ouachita Power. This equity commitment was previously supported by a letter of credit under the Corporate Credit Facility (see Note 7). The Company will retain a 50% membership interest in Ouachita Power and will continue to manage and operate the O uachita Facility. The Company recorded a gain of approximately $50.3 million, net of transaction costs related to this sale. The Company is now 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 (the "Batesville Facility") 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.

5.  INVESTMENTS IN UNCONSOLIDATED POWER PROJECTS

          The Company recognized approximately $34,830,000, $43,987,000 and $25,464,000 in income from unconsolidated investments in power projects, net of premium amortization in the accompanying consolidated statements of income for the years ended December 31, 2001, 2000 and 1999, respectively. Approximately $32,427,000, $40,001,000 and $22,998,000 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, 2001, in these projects:

          *currently under construction

          The Indiantown, Birchwood, Logan and Northampton Facilities are operated and managed by third parties that are not affiliated with the Company. The Company has 50% representations on these Facilities', management committees or boards of control, which must approve all material transactions of these projects. See Note 4 for additional discussion regarding the Ouachita 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):

6.  NET ASSETS HELD FOR SALE

          The assets and liabilities of the Batesville Facility, which was sold in March 2001 (see Note 4), were included in net assets held for sale as of December 31, 2000 as a result of management formalizing its plans to dispose of its interest in this Facility and consisted of the following (dollars in thousands):

7.  LONG-TERM DEBT

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

          The Jenks, Southaven and Caledonia projects incurred two defaults or events of default under their respective loan agreements during December 2001. The first event of default was a result of Enron Corporation ("Enron") filing for reorganization under Chapter 11 of the United States Bankruptcy Code. Enron is the parent company of National Energy Production Corporation ("NEPCO"), the construction contractor for each of these Facilities, and guarantor of NEPCO's obligations under each Facility's engineering, procurement and construction contract (the "Construction Contracts"). The second event of default occurred when these Facilities amended their Construction Contracts as a result of the Enron reorganization without the consent of the respective bank or financial institution. During February, March and April 2002, each Facility entered into amended loan agreements and received waivers for the defaults or events of default and cons ents for the amended Construction Contracts.

          Information related to the Company's borrowings and the amended terms of the Jenks, Southaven and Caledonia project financing debt are as follows:

Hopewell Facility:

          The note payable accrues interest at an annual rate equal to the applicable LIBOR rate, as chosen by the Company, plus an additional margin of 1.00% (3.04% at December 31, 2001) and matures in December 2002. This Facility's debt agreement also provides a $5.0 million letter of credit to secure the project's obligation to pay debt service. See Note 10 for additional discussion.

Portsmouth Facility:

          During September 2001, the project debt was repaid in full and the revolving credit facility was terminated in December 2001.

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 $115,263,000 of notes payable and $48,000,000 of tax-exempt industrial development bonds (the "Richmond Bonds"). The notes payable and the Richmond Bonds are part of a credit facility with a syndicate of banks that was amended during June 2000. The amended terms of the credit facility increased outstanding borrowings by $25,181,000 and extended the final maturity of the notes payable by five months to December 2007. 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 (3.06% at December 31, 2001), 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 the amended credit facility. The amended credit facility extended the bond letter of credit facility through March 2010. The annual interest rate is the yield on the Richmond Bonds plus a 1.25% to 1.50% per annum fee (2.10% at December 31, 2001).

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 $15.0 million letter of credit outstanding to support a portion of the debt reserve requirements for the 2010 and 2016 bonds. This credit facility expires in December 2005. During December 2001, the bank terminated Mid-America's ability to draw any additional amounts under the credit facility above the then outstanding letters of credit.

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 construction borrowings are expected to convert to a term loan during 2002 and will mature five years from conversion. The loan agreement accrues interest at an annual rate equal to the applicable LIBOR rate, as chosen by the Company (3.33% at December 31, 2001), plus 1.30% to 1.50% per annum. 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 $28.5 million letter of credit to secure the Facility's obligations under its conversion services agreement.

          The Company is committed to provide an equity contribution to this project of approximately $48.7 million which is supported by a letter of credit under Cogentrix Energy's Corporate Credit Facility. The Company has made $11.1 million of these contributions through December 31, 2001.

Rathdrum Facility:

          The project debt consists of $71,163,000 of term loans with banks, $49,000,000 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% (3.32% at December 31, 2001) with principal payments due quarterly through September 2019.

Dominican Republic Facility:

          The loan agreement provides borrowings up to $282.5 million to construct an approximate 300-megawatt, combined cycle oil-fired, electric generating facility located in the province of San Pedro de Macorís, Dominican Republic. Two of the three generating units achieved commercial operations prior to December 31, 2001, with the third achieving commercial operations in March 2002. The loans are provided under the following Facilities: (i) a $72.2 million bank loan, accruing interest per annum at the applicable LIBOR rate plus an applicable margin ranging from 1.75% to 2.75% (3.68% at December 31, 2001) during the 12-year loan life, (ii) $83.3 million of fixed-rate loans, guaranteed by certain export credit agencies, accruing interest per annum at fixed rates ranging from 7.71% to 7.78% during the 14-year loan lives, (iii) a $12.0 million unguaranteed loan accruing interest per annum at the lesser of a fixed-rate or LIBOR rate plus an appl icable margin (4.59% at December 31, 2001), as chosen by the Company, during the 8-year life, (iv) a $65.0 million institutional loan accruing interest at the 10-year U.S. Treasury rate plus 4% (8.65% at December 31, 2001) during the 17-year loan life and (v) a $50.0 million bank loan accruing interest per annum at the applicable LIBOR rate plus an applicable margin of 0.3% (2.23% at December 31, 2001) and maturing in 2002 (the "Equity Loan").

          The Company has committed to provide an equity contribution to this project of approximately $50.0 million which is supported by a letter of credit under Cogentrix Energy's Corporate Credit Facility. This equity contribution will repay all outstanding borrowings under the Equity Loan.

Ouachita Facility (see Note 4 for additional discussion):

          The construction loan agreement provides up to $460.0 million in borrowings, a credit support letter of credit in the maximum amount of $30.0 million, and a $10.0 million debt service reserve letter of credit. Proceeds from the borrowings are being used to construct the Ouachita Facility which began in August 2000. The Company has committed to provide an equity contribution to the project of approximately $5.3 million.

Southaven Facility:

          The 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. 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. Construction on the Facility began in May 2001. The borrowings under the credit agreement accrue interest at an annual rate equal to the applicable LIBOR rate, as chosen by the Company (3.58% at December 31, 2001), plus 1.50% during the construction period. The construction loans convert to term loans on January 1, 2004 or earlier if the Facility achieves commercial operations prior to January 1, 2004. The construction loans are due and payable in the event conversion does not occur by January 1, 2004. The term loans accrue interest per annum at an annual rate equ al to the applicable LIBOR rate plus an applicable margin ranging from 1.63% to 1.88%. The term loans mature four years after the commencement of commercial operations.

          During the construction period, the Southaven Facility's power purchaser has committed to provide up to $73.8 million in subordinated loans to the project upon the power purchaser's event of default under the conversion services agreement. The aggregate commitments provided by the banks under the construction loan agreement will be reduced to $319.7 million in conjunction with the power purchaser providing the subordinated loans.

          The Company has committed to provide an equity contribution to this project of approximately $98.4 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 $17.0 million of these contributions through December 31, 2001. The Company has also committed to provide a contingent equity guarantee to this project of up to $17.7 million on the occurrence of certain conditions including an event of default by the project's power purchaser under its conversion services agreement. Under the amended construction loan agreement, the Company provided a $14.4 million retainage letter of credit under Cogentrix Energy's Corporate Credit Facility to support the Company's obligations to make additional equity contributions to the project to cover any liquidated damages or other obligations owed by NEPCO under the Construction Contract or to support any cost over runs not otherwise paid. In addition, the Company provided a $24.7 million letter of credit under Cogentrix Energy's Corporate Credit Facility to support the Company's obligations to make additional equity contributions to the project to cover NEPCO's obligations to pay any liquidated damages under its Construction Contract.

          In addition, the Company has committed to provide supplemental equity contributions to this project if additional funds are needed to pay any unpaid obligations of NEPCO under the Construction Contract or cover certain cost overruns. The maximum amount of supplemental equity contribution is initially $10.9 million. The supplemental equity contribution is adjusted as of December 31, 2002 to $50.9 million, less construction savings realized for interest incurred during construction and construction contingency compared to the amounts in the original construction budget. Only $10.0 million of the $50.9 million supplemental equity commitment can be utilized to cover general project cost overruns. Cogentrix Energy has guaranteed the project subsidiary's obligations to provide these supplemental equity contributions. Cogentrix Energy is required to provide a letter of credit to support this guarantee in the event the credit rating of the Company's 20 04 and 2008 Notes (defined below) is below investment grade by both Moody's Investors Service, Inc. and Standard & Poor's Corporation.

Caledonia Facility:

          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. Construction on the Facility began in July 2001. The borrowings under the loan agreement accrue interest at an annual rate equal to the applicable LIBOR rate, as chosen by the Company (4.58% at December 31, 2001), plus 2.50% during the construction period. The construction loans convert to term loans on March 31, 2004 or earlier if the Facility achieves commercial operations prior to March 31, 2004. The construction loans are due and payable in the event conversion has not occurred by March 31, 2004. The term loans accrue interest per annum at an annual rate equal to the app licable LIBOR rate plus 2.50% to 4.00%. The term loans mature four years after the commencement of commercial operations.

          The Company has committed to provide an equity contribution to this project of $55.6 million which is supported by an equity contribution guarantee by Cogentrix Energy. Under the amended construction loan agreement, the Company has agreed to provide up to $20.0 million of supplemental equity contributions to this project to cover any Construction Contract costs that are in excess of the original budgeted construction cost of the project and any liquidated damages that NEPCO is obligated but unable to pay. Cogentrix Energy has provided an unsecured guarantee of the project subsidiary's obligations to provide these supplemental equity contributions.

CEA Credit Facility:

          Cogentrix Eastern America, Inc., which holds interests in certain investments in unconsolidated power projects, has a $60.0 million credit facility that matures in September 2002. The credit facility accrues interest at an annual rate equal to the applicable LIBOR plus 1.50% (3.64% at December 31, 2001).

Interest Rate Protection Agreements:

          The Company has entered into interest rate cap and interest rate swap agreements to manage its interest rate risk on its variable-rate project financing debt. The notional amounts of debt covered by these agreements as of December 31, 2001 and 2000 were approximately $114,310,000 and $125,968,000, respectively. The agreements effectively change the interest rate on the portion of debt covered by the notional amounts from a weighted average variable rate of 3.17% at December 31, 2001, to a weighted average effective rate of 6.86%. These agreements expire at various dates through July 2006.

Senior Notes:

          On March 15, 1994, Cogentrix Energy issued $100 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 Senior Notes as required by the terms of the indenture under which these 2004 notes were issue d. The 2004 Notes require an annual sinking fund payment in March 2003. The impact of the sinking fund requirements has been reflected in the schedule of future maturities of long-term debt contained herein.

          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 related to this hedge agreement were deferred and are 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%.

Corporate Credit Facility:

          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. Commitment fees related to the Corporate Credit Facility are 37.5 basis points per annum when greater than 50% of the available commitments are utilized and 50.0 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, 2001, the Company had used this credit facility to issue approximately $199.6 million of letters of credit to support equity contribution commitments for certain projects and to a lesser extent support certain Facilities' obligations und er certain of their operating agreements.

          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. This dividend was paid on April 1, 2002. In addition, these covenants did not restrict the Company's ability to declare dividends of $10.3 million and $8.7 million to the Company's shareholders for the years ended December 31, 2000 and 1999, respectively.

          Future maturities of long-term debt at December 31, 2001, 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):

          Cash paid for interest excluding amounts capitalized in construction in progress on the Company's long-term debt amounted to $97,281,000, $84,947,000 and $92,228,000 for the years ended December 31, 2001, 2000 and 1999, respectively.

8.   LEASES

          The power purchase agreements of two of the Company's 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):

          Gross investment in leases represents total capacity payments receivable over the terms of the power purchase agreements, net of executory costs, which are considered minimum lease payments in accordance with SFAS No. 13.

          The conversion services agreements at two of the Company's other Facilities have characteristics similar to operating leases in that the Electric Customer under these agreements has the right to use specific property, plant and equipment. The capacity payments of these Facilities are considered minimum lease payments in accordance with SFAS No. 13 and are recognized as lease revenue on a straight-line basis over the term of the respective conversion services agreements. As of December 31, 2001, the Company had a net deferred lease receivable of $1,538,000 representing the difference between capacity payments received and the straight-line recognition of the lease revenue for these operating leases.

          Estimated minimum lease payments to be received over the remaining term of these operating and "sales-type" capital leases as of December 31, 2001, were as follows (dollars in thousands):

9.  INCOME TAXES

          The provision (benefit) for income taxes consisted of the following (dollars in thousands):

          Reconciliations between the federal statutory income tax rate and the Company's effective income tax rate are as follows:

          The net current and noncurrent components of deferred income taxes reflected in the accompanying consolidated balance sheets as of December 31, 2001 and 2000, were as follows (dollars in thousands):

          Deferred income taxes reflect the net tax effects of (a) temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes, and (b) operating loss and tax credit carryforwards. Significant components of the Company's net deferred tax liability as of December 31, 2001 and 2000, were as follows (dollars in thousands):

          As of December 31, 2001, the Company had a net federal operating loss carryforward available to offset future federal taxable income of approximately $21,273,000 which expires in 2020. The Company also had state net operating loss carryforwards available to offset future state taxable income of approximately $330,440,000 which expire from 2008 to 2021. In addition, the Company had alternative minimum tax credit carryforwards of approximately $32,200,000 which are available to reduce future federal regular income taxes, if any, over an indefinite period.

          Cash paid for income taxes amounted to approximately $6,017,000, $4,561,000 and $2,142,000 for the years ended December 31, 2001, 2000 and 1999, respectively.

10.   COMMITMENTS AND CONTINGENCIES

          Long-Term Contracts - The Company has several long-term contractual commitments that comprise a significant portion of its financial obligations. These contractual commitments with original terms varying in length from 10 to 35 years are the basis for a major portion of the revenue and operating expenses recognized by the Company and provide for specific services to be provided at fixed or indexed prices. The major long-term contractual commitments are as follows:

          Under the terms of certain power sales agreements with certain Electric Customers, the Company is obligated to pay up to $37,350,000 in aggregate liquidated damages to the respective Electric Customers if the respective Facility does not demonstrate certain operating and reliability standards. Banks have issued letters of credit, non-recourse to Cogentrix Energy, in favor of the Electric Customers which secure the Company's obligations to the Electric Customer under this provision of the contracts. In addition, under the terms of certain power sales agreements with certain other Electric Customers, the Company has posted letters of credit in the aggregate amount of $63,850,000 to support its obligations under these power sales agreements.

          Under certain power sales agreements, the Electric Customer is permitted to reduce future payments or recover certain payments previously made upon the occurrence of certain events, which include a state utility commission prohibiting the Electric Customer from recovering such payments made under such power sales agreement. However, in most cases, the Electric Customer is prohibited from reducing or recovering such payments prior to the maturity date of the original project financing debt.

          Management Incentive Compensation Plans - The Company has entered into various incentive compensation plans with certain employees, which provide for compensation to the employees (during the period of employment) equal to a percentage, as determined by the Board of Directors, of the Company's income before income taxes. The Company incurred expense under these plans of approximately $15,562,000, $9,954,000 and $8,236,000 for the years ended December 31, 2001, 2000 and 1999, respectively.

          Employee Benefit Plans - The Company sponsors a defined contribution 401(k) savings plan for its full-time employees. The Company matches employees' contributions to the plan up to specified limitations. Company contributions to the plan were approximately $2,260,000, $2,103,000 and $1,664,000 for the years ended December 31, 2001, 2000 and 1999, respectively.

          The Company has a non-qualified Supplemental Retirement Plan agreement with certain directors and officers. Under the plan, the participants are able to elect to have up to 90% of their compensation deferred. In addition, the Company will credit the participant's deferral account, up to specified limitations, in proportion to the participant's deferral. The participants' account balances are distributable upon termination of employment or death. The Company purchases insurance on the participants' lives (cash surrender value of approximately $12,713,000 and $9,354,000 at December 31, 2001 and 2000, respectively) and other investments to fully fund the liability under the plan on an annual basis. The Company is owner and beneficiary of the insurance policies.

          Guarantees - In connection with its non-recourse project financings and certain other subsidiary contracts, the Company and its subsidiary, Cogentrix, Inc., have expressly undertaken certain limited obligations and commitments, most of which will only be effective or will be terminated upon the occurrence of future events. These obligations and commitments include guarantees by Cogentrix, Inc. of a certain subsidiary's obligation capped at $1.5 million and certain subsidiaries' performance under their contracts with one Electric Customer. In addition, Cogentrix Energy has indemnified the project lenders at the Hopewell Facility for any cash deficits this subsidiary could experience as a result of incurring certain costs, subject to an aggregate cap of $10.6 million.

          Cogentrix Delaware Holdings, Inc., a wholly-owned subsidiary of Cogentrix Energy, has guaranteed all of the existing and future senior, unsecured outstanding indebtedness for borrowed money of Cogentrix Energy. This guarantee, provided for in the credit agreement for the Corporate Credit Facility, expires by its terms in 2003, unless the term is extended. The agreement under which the guarantee was given provides that the terms or provisions of the guarantee may be waived, amended, supplemented or otherwise modified at any time and from time to time by Cogentrix Delaware Holdings, Inc. and the agent bank for the lenders under the Corporate Credit Facility.

          Construction - Under the terms of their conversion services agreements, certain project subsidiaries with Facilities under construction are required to pay delay liquidated damages or provide replacement power in the event they do not achieve commercial operations by a designated start date. The construction contractor is also required to pay the project subsidiaries' liquidated damages in the event construction is not completed by a designated start date which is consistent with the date under the respective conversion services agreements.

          Equipment Deposits - The Company has entered into commitments with a turbine supplier and a heat recovery steam generator ("HRSG") supplier to purchase a specified number of turbines and HRSG's with specified delivery dates. The Company has made approximately $93.6 million in non-refundable deposits related to these commitments through December 31, 2001. The Company expects to make additional progress payments of $84.0 million in 2002.

          Sale of Project Interest - Caledonia Generating, LLC ("Caledonia Generating") and its sole member, Cogentrix Caledonia Holdings I, Inc. ("Cogentrix Caledonia"), both indirect wholly-owned subsidiaries of Cogentrix Energy, entered into a membership interest purchase agreement with MEP-III, LLC ("MEP-III"), an indirect wholly-owned subsidiary of GECC, whereby MEP-III has committed, subject to certain conditions, to acquire a 50% membership interest in Caledonia Generating at or around the commercial operations date. In exchange for the membership interest, MEP-III will contribute approximately $55.6 million to Caledonia Generating and pay Cogentrix Caledonia a purchase price to be determined based on Caledonia Generating's project economics at the commercial operations date. The Company would retain a 50% membership interest in Caledonia Generating and would continue to manage and operate the Facility as managing member.

          Claims and Litigation - One of the Company's indirect, wholly-owned subsidiaries is party to certain product liability claims related to the sale of coal combustion by-products for use in 1997-1998 in various construction projects. Management cannot currently estimate the range of possible loss, if any, the Company will ultimately bear as a result of these claims. However, management believes--based on its 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 its consolidated financial position or results of operations or on Cogentrix Energy's ability to generate sufficient cash flow to service its outstanding debt.

          In addition to the litigation described above, the Company experiences other routine litigation in the normal course of business. The Company's management is of the opinion that none of this routine litigation will have a material adverse impact on its consolidated financial position or results of operations.

11.  FUNDS HELD BY TRUSTEES

          The majority of revenue received by the Company is required by the terms of various credit agreements to be deposited in accounts administered by certain banks (the "Trustees"). The Trustees invest funds held in these accounts at the direction of the Company. These accounts are established for the purpose of depositing all receipts and monitoring all disbursements of each Facility. In addition, special accounts are established to provide debt service payments and income taxes. The funds in these accounts are pledged as security under the project financing agreements of each subsidiary.

          Funds held by Trustees were approximately $120,109,000 and $85,654,000 at December 31, 2001 and 2000, respectively. Debt service account balances are reflected as restricted cash, whereas all other accounts are classified as cash and cash equivalents in the accompanying consolidated balance sheets. Included in the December 31, 2001, balance of restricted cash is approximately $53,020,000 of funds received from draws on letters of credit benefiting Green Country Energy, LLC ("Green Country"), a wholly-owned subsidiary of the Company and owner of the Jenks Facility. The letters of credit were provided on behalf of NEPCO and supported a completion deadline guaranteed by NEPCO. All or part of these funds may be utilized to pay for delay liquidated damages owed to Green Country by NEPCO as a result of the late completion of the Facility and for any other obligations owed by NEPCO under the Construction Contract.

12.  FAIR VALUE OF FINANCIAL INSTRUMENTS AND CONCENTRATION OF CREDIT RISKS

          The Company invests its temporary cash balances in United States government obligations, corporate obligations and financial instruments of highly-rated financial institutions. A substantial portion of the Company's accounts receivable is from two major regulated electric utilities and the associated credit risks are limited.

          The carrying values reflected in the accompanying consolidated balance sheets at December 31, 2001 and 2000, approximate the fair values for cash and cash equivalents and variable-rate long-term debt. Investments in certificates of deposit and restricted investments are included in restricted cash and are reported at fair market value, which approximates cost, at December 31, 2001 and 2000. The fair value of the Company's fixed-rate borrowings at December 31, 2001 and 2000, is $59,977,000 higher and $32,289,000 higher than the historical carrying value of $1,043,476,000 and $997,190,000, respectively. In making such calculations, the Company utilized credit reviews, quoted market prices and discounted cash flow analyses, as appropriate.

          The Company is exposed to credit-related losses in the event of non-performance by counterparties to the Company's interest rate protection agreements (see Note 7). The Company does not obtain collateral or other security to support such agreements but continually monitors its positions with, and the credit quality of, the counterparties to such agreements.

13.  RELATED PARTY TRANSACTIONS

          In March 2000, Cogentrix Energy established a revolving credit facility whereby each of its five shareholders may borrow from time to time up to $1,000,000 from Cogentrix Energy on a revolving basis. During July 2001, this revolving credit facility was amended to provide borrowings up to $2,000,000 per shareholder. Shareholder borrowings accrue interest at the prime rate of a major United States bank plus 1.0%, payable annually. Principal payments on any borrowings made under the facility are due in three equal annual installments on each annual shareholder dividend payment date following the borrowing. Upon the sale of any of a shareholder's shares (except a permitted transfer), the principal balance outstanding will become due and payable immediately. As of December 31, 2001 and 2000, respectively, there was $4,000,000 and $200,000, respectively, outstanding under this shareholder revolving credit facility. These amounts are recorded as a reduction to shareholders' equity in the accompanying consolidated financial statements.

          Until October 2001, the Company leased certain equipment, its principal executive office building and land from an affiliated entity. Payments by the Company under these lease agreements were approximately $1,239,000, $1,633,000 and $1,887,000 for the years ended December 31, 2001, 2000 and 1999, respectively. During October 2001, the Company purchased, at fair market value, the leased equipment and principal executive office building from the affiliated entity for $7,659,000 in the aggregate.

          A shareholder, director and former executive officer was a participant in management incentive compensation plans (see Note 10) while employed as an executive officer of the Company and continues to receive incentive compensation annually pursuant to such plans equal to a percentage of the net cash flow, as defined, of certain subsidiaries. Total compensation to the shareholder under the consulting agreement and incentive compensation plans was approximately $200,000, $709,000 and $290,000 for the years ended December 31, 2001, 2000 and 1999, respectively.

          The Company entered into a consulting agreement with a shareholder, director and former executive officer to provide consulting services related to general business matters. The Company made payments of $219,000 and $350,000 for the years ended December 31, 2001 and 2000, respectively, and the agreement provides for monthly payments of $15,644 for January 2002 through December 2003 and monthly payments of $10,429 for January 2004 through December 2004.

The accompanying condensed notes to condensed financial statements
are an integral part of this schedule.

The accompanying condensed notes to condensed financial statements

are an integral part of this schedule.

The accompanying condensed notes to condensed financial statements
are an integral part of this schedule

1.  SIGNIFICANT ACCOUNTING POLICIES

          These condensed notes should be read in conjunction with the consolidated financial statements and accompanying notes of Cogentrix Energy, Inc. ("Cogentrix Energy", the Registrant) and subsidiary Companies, (the "Company").

          Accounting for Subsidiaries - Cogentrix Energy has accounted for its investment in and earnings of its subsidiaries on the equity method in the condensed financial information.

          Income Taxes - The benefit for income taxes has been computed based on the Company's consolidated effective income tax rate.

          Reclassifications - Certain amounts in the accompanying condensed financial statements for the fiscal year ended December 31, 2000 and 1999 have been reclassified from their original presentation to conform with the presentation for the year ended December 31, 2001.

2.  LONG-TERM DEBT

     Senior Notes

          On March 15, 1994, Cogentrix Energy issued $100 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 United States 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 that was deferred and included as part of the 2004 Notes on the accompanying condensed balance sheets of the Registrant. This deferred gain will be 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 Senior Notes as required by the terms of the indenture under which these 2004 Notes were issued. The 2004 Notes require an annual sinking funds payment in March 2003. The impact of the sinking fund requirements has been reflected in the schedule of future maturities of long-term debt contained herein.

          On October 20, 1998, Cogentrix Energy issued $220 million of registered, unsecured 8.75% senior notes due 2008 (the "2008 Notes"). The 2008 Notes were issued at a discount resulting in an effective 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. The settlement costs of approximately $22.1 million related to this hedge agreement were deferred and will be recognized over the term of the 2008 Notes resulting in an overall effective rate of approximately 9.59%.

          In September 2000, Cogentrix Energy sold 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%.

          Future maturities of long-term debt at December 31, 2001, excluding the unamortized balance of the deferred gains and losses on hedge transactions and excluding the net unamortized premium, were as follows (dollars in thousands):

     Corporate Credit Facility:

          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 of Cogentrix Energy's 2004 and 2008 Notes. Commitment fees related to the Corporate Credit Facility are 37.5 basis points per annum when greater than 50% of the available commitments are utilized and 50.0 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, 2001, the Company has used this credit facility to issue approximately $199.6 million of letters of credit to support equity contribution commitments for certain projects and, to a lesser extent, support certain subsidiaries' obligati ons under certain of their operating agreements.

          The project financing debt of Cogentrix Energy's subsidiaries is substantially non-recourse to Cogentrix Energy. The project financing agreements of the Company's subsidiaries, the indentures for the 2004 and 2008 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 subsidiaries' facilities, as well as the long-term contracts which support them, are pledged as collateral for the Company's obligations under the project financing agreements.

          Cogentrix Delaware Holdings, Inc., a wholly-owned subsidiary of Cogentrix Energy, has guaranteed all of the existing and future senior, unsecured outstanding indebtedness for borrowed money of Cogentrix Energy. This guarantee, provided for in the credit agreement for the Corporate Credit Facility, expires by its terms in 2003. The agreement under which the guarantee was given provides that the terms or provisions of the guarantee may be waived, amended, supplemented or otherwise modified at any time and from time to time by Cogentrix Delaware Holdings, Inc. and the agent bank for the lenders under the credit agreement.

3. GUARANTEES

          Cogentrix Energy has committed to provide a contingent equity guarantee to a project subsidiary up to $17.7 million on the occurrence of certain conditions including an event of default by the power purchaser under the project subsidiary's conversion services agreement.

          Cogentrix Energy has guaranteed a project subsidiary's obligation to make $37.1 million of its remaining equity contribution to a project this subsidiary has under construction (the "Equity Guarantee"). In addition, Cogentrix Energy has guaranteed two project subsidiaries' obligations to make supplemental equity contributions to projects which these subsidiaries have under construction in the event certain events occur in the future. The supplemental equity contributions are initially $10.9 million for one project subsidiary (the "First Supplemental Guarantee") and up to $20.0 million for the second project subsidiary. The First Supplemental Guarantee is adjusted as of December 31, 2002 to up to $50.9 million, less certain savings. Cogentrix Energy is required to post a letter of credit to support the First Supplemental Guarantee in the event the credit rating of the 2004 and 2008 Notes is below investment grade by two major rating agencies. See Note 7 to the Company's consolidated financial statements for additional discussion regarding these guarantees.

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

          None

Item 10.  Directors and Executive Officers of the Registrant

The directors and executive officers of Cogentrix Energy are set forth below.

Summary Compensation Table

______________________

Compensation Pursuant to Incentive Compensation Plans

     Profit-Sharing Plan

          We have a profit-sharing plan which is a non-qualified incentive compensation plan for the benefit of approximately 57 employees of Cogentrix. Under our profit-sharing plan, we have entered into arrangements with each of our executive officers, which provide for annual cash compensation distribution awards to each participant equal to a designated percentage of our adjusted net income before taxes each fiscal year plus the amount of any accrual for payments to be made under our profit-sharing plan, with the designated percentage determined annually at the discretion of our Chief Executive Officer or Chief Operating Officer based on criteria they deem appropriate. For the fiscal year ended December 31, 2001, David J. Lewis earned $1,630,871, Mark F. Miller earned $1,174,227, James R. Pagano earned $913,288, Dennis W. Alexander earned $652,348, and Thomas F. Schwartz earned $521,879 under our profit sharing plan. These amounts are included in the Bonus column in the Summary Compensation Table above.

          In the event a participant in our profit-sharing plan is involuntarily terminated (or for certain participants, voluntarily terminated) by Cogentrix (for a reason other than death, total disability, retirement or termination by Cogentrix for willful misconduct), these participants are entitled to receive a severance benefit equal to a percentage (ranging from 25% for three years or less of full-time employment to a maximum of 200% after ten years or more of full-time employment) of the highest annual distribution to which the employee was or is entitled for any of the three full years preceding the termination date. In the event of a participant's death or total disability, the participant (or his or her beneficiary) is entitled to receive from zero to five years of annual distribution awards thereafter, depending upon the participant's length of service with Cogentrix.

     Executive Incentive Bonus Plan

          In addition to the annual cash compensation distribution awards payable under our profit-sharing plan, each of the Named Executive Officers, with the exception of David J. Lewis, may receive additional incentive cash compensation awards, determined on a sliding scale, if we achieve contractually specified levels of net income before income tax targets for a given fiscal year. For the fiscal year ended December 31, 2001, each of the Named Executive Officers, with the exception of David J. Lewis, earned $1,000,000 under the executive incentive bonus plan.

Employment Agreements with Named Executive Officers

     David J. Lewis

          In March 1999, the board of directors elected David J. Lewis Chairman of the Board of Cogentrix. He was previously elected Chief Executive Officer of Cogentrix in August 1995. George T. Lewis, Jr., the former Chief Executive Officer and Chairman of the Board, will serve as Chairman Emeritus. We have an employment agreement with David J. Lewis through August 2005 which provides for a base annual salary for each fiscal year at least equal to the base salary for the immediately preceding fiscal year. In addition to the base salary, Mr. Lewis is entitled to participate in our profit sharing plan, at a level of no less than 1.25% of net income before taxes, and to receive annual incentive compensation in an amount determined by the board of directors, which amount, when combined with the base salary and profit sharing payable to him, shall be at least sufficient to provide him with total annual compensation that is competitive with total annual compe nsation offered by other similarly situated companies to their employees in comparable positions.

          Upon our giving notice, the employment agreement is terminable in the event at least two-thirds of the board of directors terminates Mr. Lewis' employment for cause. In addition, we may terminate the agreement at any time at our option by a vote of at least two-thirds of the directors then in office. In the event we terminate his employment, other than for cause, Mr. Lewis is entitled to continue to receive base salary, performance bonus (based on historical levels) and distributions under the profit sharing plan through the remainder of the term of this employment agreement.

          Mr. Lewis can terminate his employment for good reason as a result of

         - a change in control of Cogentrix,

          - a change in title, authority or duties, or

          - our failure to make any other payment to Mr. Lewis or our breach of the employment agreement.

          If Mr. Lewis elects to terminate his employment for good reason, he is entitled to continue to receive, for five years, an amount equal to the average annual salary, bonus and profit sharing distribution received prior to his termination.

     Mark F. Miller

          We have an employment agreement with Mark F. Miller through May 2007, which we amended with his consent in February 2001 and November 2001, which provides a minimum base annual salary of $350,000, which at the beginning of each fiscal year is increased by an amount, if positive, that will reflect increases in the cost of living. He is also entitled to participate in our profit sharing plan, at a level of no less than 0.9% of net income before taxes, our executive incentive bonus plan, and to receive a performance bonus each fiscal year, the level of which is determined in the sole discretion of the Chief Executive Officer. We have the right to terminate Mr. Miller's employment upon sixty days written notice. In the event we terminate his employment, other than for cause, Mr. Miller is entitled to receive within 30 days of his termination, a lump sum severance payment in an amount equal to the total compensation (based upon historical levels) that Mr . Miller would have received through the remainder of the term of the employment agreement.

          Mr. Miller is entitled to the same severance payment in the event a change of control occurs or he terminates his employment for good reason as a result of our breach of the employment agreement or a change in title, authority or duties.

     Dennis W. Alexander

          We have an employment agreement with Dennis W. Alexander, which we amended with his consent in February 2001 and November 2001. Under the employment agreement, Mr. Alexander is entitled to a minimum base annual salary of $180,000, subject to adjustment in future years. He is also entitled to participate in our profit sharing plan, at a level of no less than 0.3% of net income before taxes, and our executive incentive bonus plan. The employment agreement is for a one-year term that renews automatically at the end of each calendar year unless we previously exercise our right to terminate Mr. Alexander's employment. We have the right to terminate Mr. Alexander's employment upon 30 days' written notice. In the event we terminate his employment or a change in control occurs, Mr. Alexander is entitled to receive a severance payment in an amount equal to two times his total compensation earned in the prior calendar year, including any fees he received for serving as a member of the Board of Directors.

     James R. Pagano

          We have an employment agreement with Mr. Pagano, which we amended with his consent in February 2001 and November 2001. Under the employment agreement, Mr. Pagano is entitled to a minimum base annual salary of $306,000, subject to adjustment in future years. He is also entitled to participate in our profit sharing plan, at a level of no less than 0.7% of net income before taxes, and our executive incentive bonus plan. The employment agreement is for a one-year term that renews automatically at the end of each calendar year unless we previously exercise our right to terminate Mr. Pagano's employment. We have the right to terminate Mr. Pagano's employment upon 30 days' written notice. In the event we terminate his employment or a change in control occurs, Mr. Pagano is entitled to receive a severance payment in an amount equal to five times his total compensation earned in the prior calendar year.

     Thomas F. Schwartz

          In February 2001, we entered into an employment agreement with Mr. Schwartz, which we amended with his consent in November 2001. Under the employment agreement, Mr. Schwartz is entitled to a minimum base annual salary of $230,625, subject to adjustment in future years. He is also entitled to participate in our profit sharing plan, at a level of no less than 0.3% of net income before taxes, and our executive incentive bonus plan. The employment agreement is for a one-year term that renews automatically at the end of each calendar year unless we previously exercise our right to terminate Mr. Schwartz's employment. We have the right to terminate Mr. Schwartz's employment upon 30 days' written notice. In the event we terminate his employment or a change in control occurs, Mr. Schwartz is entitled to receive a severance payment in an amount equal to two times his total compensation earned in the prior calendar year.

Directors' Compensation and Consulting Agreements

          Directors, including employee directors, receive an annual retainer of $30,000 for service on the board of directors. In addition, for each meeting attended, each director receives a fee of $1,500. During the year ended December 31, 2001, there were eleven meetings of Cogentrix Energy's board of directors.

          We have entered into consulting agreements with Messrs. Garrett and Tillinghast each of which provides for payment of $15,000 annually to each of them for consulting services to be rendered to us.

     Robert W. Lewis

          While Robert W. Lewis was employed as an executive officer, Cogentrix entered into a non-qualified incentive compensation agreement with him similar to the agreements described above under "- Facility Cash Flow Incentive Compensation Agreements" providing for him to receive incentive compensation annually equal to a designated percentage of the net cash flow for the fiscal year of two of our facilities. Our obligation to make such annual payments to him continues through June 30, 2007. We have agreed to pay him an annual minimum payment of $200,000 regardless of whether his actual annual distribution would yield such amount. Robert W. Lewis must repay to Cogentrix, on or before January 31, 2008, an amount equal to the aggregate amount of minimum payments made in excess of the actual annual distributions which he was entitled to receive. The actual amount of the distribution Mr. Lewis received pursuant to his facility cash flow compensation agree ment for the year ended December 31, 2001 and 2000 was $200,000 and $726,009, respectively.

          If at any time through June 1, 2007, Mr. Lewis sells or transfers any of the shares of common stock of Cogentrix Energy held by him to anyone other than other designated members of the Lewis family without granting Cogentrix Energy a right of first refusal with respect to the shares sold or transferred, he will forfeit his right to the annual distributions under his facility cash flow incentive compensation agreement and the right to the annual minimum payment of $200,000.

     James E. Lewis

          On January 1, 2000, we entered into a consulting agreement with James E. Lewis, a shareholder, director, officer and former employee of Cogentrix. Under the terms of the consulting agreement, Mr. Lewis is required, subject to certain limits, to be available during customary business hours for consultations, either in person or by telephone, with respect to such of our business and affairs as we may reasonably call on him to furnish.

          Pursuant to the consulting agreement, base compensation is payable to Mr. Lewis in the following amounts for the following periods:

          In the event of Mr. Lewis' death or inability to provide services due to disability, we are obligated to continue making payments, when due, to him or his estate.



Item 12.   Security Ownership of Certain Beneficial Owners and Management

          All of the issued and outstanding shares of common stock of Cogentrix Energy are beneficially owned as follows:

Item 13.  Certain Relationships and Related Transactions

          The transactions described or referred to below were entered into between related parties. In connection with the public offering of our Senior Notes conducted in March 1994, our board of directors adopted a policy that all subsequent material transactions with related parties must be on terms no less favorable than could be obtained from third parties and that any variance from this policy is subject to approval by a majority of our disinterested directors. The indentures and the covenants of the Corporate Credit Facility place certain limitations on our ability to enter into material transactions with related parties as well.

Leases and Real Property Transactions

          Until October 2001, Equipment Leasing Partners ("ELP"), a North Carolina general partnership consisting of four of our shareholders, George T. Lewis, Jr., David J. Lewis, James E. Lewis and Robert W. Lewis, owned and leased certain equipment to our project subsidiaries related to the operations of the plants. In October 2001, all equipment previously leased by the Company was purchased from ELP at fair market value (approximately $1.0 million). Each of the partners in ELP is a member of our board of directors. David J. Lewis is Chairman and Chief Executive Officer of Cogentrix. Total rent paid by us to ELP under such equipment leases was approximately $444,000, $633,000 and $901,000 for the fiscal years ended December 31, 2001, 2000 and 1999, respectively.

          Until October 2001, ELP also owned and leased to us our executive offices under a long-term lease with an initial term expiring in 2004. In October 2001, the Company purchased the building at fair market value (approximately $6.7 million) from ELP. Total rent paid by us to ELP under such lease was approximately $677,000, $882,000 and $868,000 for the fiscal years ended December 31, 2001, 2000 and 1999, respectively.

          Until October 2001, ELP leased the land on which our executive offices are located under a long-term ground lease from an unrelated third party with an initial term expiring in 2047, all payments under which are guaranteed by Cogentrix. In October 2001, the lease was assigned from ELP to the Company. Total amounts paid by ELP and the Company under such lease were approximately $118,000 for the years ended December 31, 2001, 2000 and 1999, respectively.

Facility Cash Flow Incentive Compensation Agreements

          We have entered into an agreement with one of the beneficial owners of our outstanding shares of common stock, who is also a director, that provides for the receipt of annual distributions equal to a designated percentage of the net cash flow for each fiscal year of two of our facilities. See "Executive Compensation - Directors' Compensation and Consulting Agreements" herein.

Shareholder Stock Transfer Agreement

          In August 1994, George T. Lewis, Jr. entered into an agreement with Betty G. Lewis ("Ms. Lewis") providing for, among other things, the transfer by George T. Lewis, Jr. of a portion of his shares of our common stock to Ms. Lewis.

          In accordance with the agreement, if Ms. Lewis desires to transfer or otherwise dispose of any of her shares of common stock of Cogentrix, she must first offer to sell them to us at a price equal to a bona fide offer from an unrelated party. Any shares, the offer of sale of which is not accepted by us after receipt of the written offer, must be offered by Ms. Lewis at the same price to the other shareholders, who have the right to purchase such shares on a pro rata basis determined in accordance with the then current stock ownership of those shareholders. In the event neither we nor the other shareholders notify Ms. Lewis of its or their intention to purchase her shares within 15 days after receipt of the written offer, Ms. Lewis shall have the right for 90 days thereafter to consummate the sale of her shares with the unrelated party who provided the bona fide offer.

Shareholder Revolving Credit Facility

          Cogentrix Energy has a revolving credit facility whereby each of its shareholders may borrow from time to time up to $2,000,000 from Cogentrix Energy on a revolving basis. Shareholder borrowings will 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 each annual shareholder dividend payment date following the borrowing. Upon the sale of any of a shareholder's shares (except a permitted transfer), the principal balance outstanding together with accrued interest will become due and payable immediately. The largest aggregate amount of indebtedness outstanding exceeding $60,000 at any time during the last fiscal year from any shareholder and outstanding balance at December 31, 2001 was as follows:

Item 14.  Exhibits and Financial Statement Schedules and Reports on 8-K