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.