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                UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549
                             ---------------------

                                   FORM 10-K

<TABLE>
<C>               <S>
   (MARK ONE)
      [X]         ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
                  THE SECURITIES EXCHANGE ACT OF 1934

                  FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999

                                               OR

      [  ]        TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF
                  THE SECURITIES EXCHANGE ACT OF 1934

                  FOR THE TRANSITION PERIOD FROM ____________ TO ____________
</TABLE>

                        COMMISSION FILE NUMBER: 33-74254

                             COGENTRIX ENERGY, INC.
             (Exact name of registrant as specified in its charter)

<TABLE>
<S>                                         <C>   <C>
              NORTH CAROLINA                                      56-1853081
     (State or other jurisdiction of                           (I.R.S. Employer
      incorporation or organization)                         Identification No.)

        9405 ARROWPOINT BOULEVARD                                 28273-8110
        CHARLOTTE, NORTH CAROLINA                                 (Zip Code)
 (Address of principal executive offices)
</TABLE>

       Registrant's telephone number, including area code: (704) 525-3800

            Securities registered pursuant to Section 12(b) of Act:
                                      NONE

            Securities registered pursuant to Section 12(g) of Act:
                                      NONE

     Indicate by checkmark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. [X] Yes      [ ] No

     Indicate by checkmark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]

     Number of shares of Common Stock, no par value, outstanding at March 30,
2000:       282,000

                      DOCUMENTS INCORPORATED BY REFERENCE:

                                      NONE
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                             COGENTRIX ENERGY, INC.

                      INDEX TO ANNUAL REPORT ON FORM 10-K

<TABLE>
<CAPTION>
                                                                         PAGE
                                                                         ----
<S>        <C>                                                           <C>
PART I
Item 1:    Business....................................................    3
Item 2:    Properties..................................................   23
Item 3:    Legal Proceedings...........................................   23
Item 4:    Submission of Matters to a Vote of Security Holders.........   23

PART II
Item 5:    Market for the Registrant's Common Stock and Related
           Shareholder Matters.........................................   24
Item 6:    Selected Consolidated Financial Data........................   25
Item 7:    Management's Discussion and Analysis of Financial Condition
           and Results of Operations...................................   26
Item 8:    Financial Statements and Supplementary Data.................   37
Item 9:    Changes in and Disagreements with Accountants on Accounting
           and Financial Disclosure....................................   68

PART III
Item 10:   Directors and Executive Officers of the Registrant..........   68
Item 11:   Executive Compensation......................................   71
Item 12:   Security Ownership of Certain Beneficial Owners and
           Management..................................................   75
Item 13:   Certain Relationships and Related Transactions..............   76

PART IV
Item 14:   Exhibits, Financial Statement Schedules and Reports on Form
           8-K.........................................................   77

Signatures.............................................................   86
</TABLE>

                                        2
<PAGE>   3

                                     PART I

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, principally in the United States. We derive most of our
revenue from the sale of electricity, but we also produce and sell steam. We
sell the electricity we generate, primarily under long-term power purchase
agreements, to regulated electric utilities and power marketers. 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 25 electric
generating facilities in the United States. Our 25 plants are designed to
operate at a total production capability of approximately 4,000 megawatts. After
taking into account our part interests in the 16 plants that are not
wholly-owned by us, which range from 1.7% to approximately 74%, our net
ownership interests in the total production capability of our 25 electric
generating facilities is approximately 1,840 megawatts. We currently operate 12
of our facilities, 10 of which we developed and constructed.

     We also have an ownership interest in and will operate three facilities
currently under construction in Mississippi, Oklahoma and Idaho. Once these
facilities begin operation, we will have ownership interests in a total of 28
domestic electric generating facilities that are designed with a total
production capability of approximately 5,870 megawatts. Our net equity interest
in the total production capability of those 28 facilities will be approximately
3,190 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."

TRENDS AFFECTING THE DOMESTIC ELECTRIC GENERATING INDUSTRY AND OUR BUSINESS

  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 will lead to the transformation of the existing regulated
market, which sells to a captive customer base, 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. 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, some
utilities' managements have 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

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<PAGE>   4

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 energy prices.

  Expansion of our 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 qualifying facilities, are not required to use
alternative or renewable fuels or to have useful thermal energy output. See
"Regulation -- Energy Regulations" herein.

OUR DEVELOPMENT AND ACQUISITION 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 three market segments for our future acquisition and
development activities. They are:

     - Developing new, electric generating facilities using natural gas as fuel

     - Acquiring interests in existing domestic electric generating plants

     - Developing, owning, managing and operating on-site cogenerating
       facilities for large industrial customers with significant energy needs

     Developing New Electric Generating Plants.  We intend to pursue domestic
development of new, highly-efficient, low-cost plants, concentrating on
facilities that use natural gas as fuel. We expect these facilities to enter
into long-term contractual arrangements with fuel suppliers, electric utilities
or power marketers. These contractual arrangements will provide us a scheduled
and/or indexed payment for electricity and result in the fuel supplier, electric
utility or power marketer assuming the risks associated with energy price
fluctuations. We also intend to pursue international project development
opportunities on a highly selective basis. We expect to do so only in those
countries where demand for power is growing rapidly, private investment is
encouraged and favorable financing conditions exist.

     Acquiring Interests in Existing Domestic Electric Generating Plants.  Our
candidates for future acquisitions will generally already have entered into
power sales contracts with electric utilities or other customers whose senior
unsecured debt carries investment-grade credit ratings. We may also seek to
acquire interests in electric generating facilities that do not have contracts
in place but are nonetheless highly efficient, low-cost providers that can take
advantage of opportunities in a rapidly deregulating energy market. If we do, we
intend to protect Cogentrix against the risk of changes in the market price for
electricity by entering into contracts at the time of acquisition with fuel
suppliers, utilities or power marketers which reduce or eliminate our exposure
to this risk by establishing future prices and quantities for the electricity
produced independent of the short-term market.

     Developing New or Managing Existing Plants for Industrial Companies.  Many
large, industrial companies with significant energy needs own on-site facilities
for generating the electricity and producing the steam they require for their
manufacturing, refining or other operations. We believe that cogenerating
facilities with state-of-the-art technology developed by us could replace or
upgrade existing facilities employing older

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<PAGE>   5

technology that many of these industrial companies currently operate themselves.
We also expect that many industrial companies choosing not to replace their
existing facilities will seek to contract with companies like Cogentrix to
manage and operate their existing facilities.

     We are concentrating on opportunities to develop or acquire interests in
mid-sized electric generating facilities which use low-cost, state-of-the-art
proven technology. We target projects that will allow us to capitalize on our
reputation as a low-cost, efficient and reliable provider. We seek to manage the
risks associated with owning and operating electric generating facilities by
emphasizing diversification and balance among our investments in terms of the
following criteria:

     - the geographic location of the facilities in which we have an ownership
       interest

     - the electric utility or power marketing customers for the electricity we
       generate and the industrial customers for the steam we produce

     - the technology we employ to generate electricity and produce steam

     - the coal, gas and other fuel suppliers to our plants

PROJECTS UNDER DEVELOPMENT

     Rathdrum, Idaho Project.  We are developing jointly with Avista Power, Inc.
a 270-megawatt electric generating facility to be located in Rathdrum, Idaho.
Avista Turbine Power, Inc. will deliver natural gas to the plant and purchase
the electrical output of the facility under a 25 year power purchase agreement.
Cogentrix will have a 51% ownership interest and Avista Power will have a 49%
ownership interest in the facility. We will have the lead role for the
development, construction and operation of the facility.

     Subsequent to December 31, 1999, we closed the financing with a bank and a
financial institution on a $126 million construction loan to fund the
construction of the facility in Rathdrum, Idaho. We have begun construction and
expect commercial operations to commence in the third quarter of 2001.

     Dominican Republic Project.  We are in the advanced stages of developing a
300 megawatt electric generating facility in the Dominican Republic. The project
will utilize fuel oil-fired, combined-cycle technology. We are serving as lead
developer in a partnership with Commonwealth Development Corporation of Great
Britain. The facility will sell electricity under a 20-year power purchase
agreement with the Corporacion Dominicana de Electricidad ("CDE") supported by a
Dominican government guarantee of the payment obligations. The project is
expected to close financing and commence construction in the second quarter of
2000 with a commencement of operations in 2001.

PROJECT AGREEMENTS, FINANCING AND OPERATING ARRANGEMENTS FOR OUR FACILITIES

  Project Agreements

     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,
which 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

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<PAGE>   6

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.

     Many 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 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 cover the operating, maintenance and fuel costs
incurred by the operating subsidiary to generate electricity, are received only
for each kilowatt hour delivered.

     With some exceptions, our facilities produce process steam for use by an
industrial customer which 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 purchasing utility. 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 financed primarily under financing arrangements at the
project subsidiary level which, except as noted below, require the loans to be
repaid solely from the project subsidiary'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 interests in that project subsidiary. 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 or dividends or for the payment of subordinated
debt service, where there are subordinated lenders.

     Our facilities are financed using a high proportion of debt to equity. This
leveraged financing permits us 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 or lease obligations. The
lenders to each project subsidiary 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,
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 would only retain an interest in the property remaining, if any,
after all debts and obligations were paid.

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<PAGE>   7

     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 we have granted to an industrial steam customer and to a utility and
certain 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 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 from 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. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations."

     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

     Unlike many independent power producers who contract with third-party
operators, we operate many of our facilities. When we do operate a facility, our
project subsidiary employs directly the persons 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
operate for the periods indicated.

<TABLE>
<CAPTION>
                           PERIOD                             AVERAGE AVAILABILITY
                           ------                             --------------------
<S>                                                           <C>
Year ended December 31, 1999................................         95.6%
Year ended December 31, 1998................................         96.4%
Year ended December 31, 1997................................         97.2%
</TABLE>

     We provide to all but one of the facilities we operate administrative and
management services for a periodic fee, which 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.

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  Ash Removal

     Project subsidiaries owning nine of our coal-fired plants contract with our
subsidiary, ReUse Technology, to remove coal ash generated by such facilities.
As an alternative to disposing coal ash in landfills, ReUse Technology uses coal
ash in the manufacturing and production of various ash derived products for
resale.

FACILITIES UNDER CONSTRUCTION

     In August 1998, we acquired an approximate 52% interest in a 800-megawatt
combined-cycle, natural gas-fired electric generating facility under
construction in Batesville, Mississippi. We will operate this facility, which is
scheduled to begin operation in summer 2000. Electricity generated by the plant
will be sold under long-term power purchase agreements with two utilities. Both
of these utilities have senior, unsecured debt outstanding that
nationally-recognized credit rating agencies have rated investment grade.

     In December 1999, Cogentrix closed financing and commenced construction on
an 800 megawatt combined-cycle, natural gas-fired electric generating facility
in Jenks, Oklahoma. PECO Energy's Power Team will deliver natural gas to the
plant and purchase the electricity under a long term power purchase agreement.
This facility, which we will operate and manage, is scheduled to commence
commercial operations in early 2002.

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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, 1999, two
regulated utility customers accounted for approximately 64% 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. As a result of recent growth, our future
operations will be more diverse with regard to both geography and fuel source
and less dependent on any single project or customer.

<TABLE>
<CAPTION>
                                                                                                OUR
                                                                                  OUR       NET EQUITY
                                                                                PERCENT     INTEREST IN
                                                                     PLANT     OWNERSHIP       PLANT              POWER
        FACILITY                 LOCATION              FUEL        MEGAWATTS   INTEREST      MEGAWATTS      PURCHASING UTILITY
        --------                 --------              ----        ---------   ---------    -----------   ----------------------
<S>                       <C>                     <C>              <C>         <C>          <C>           <C>
Elizabethtown...........  Elizabethtown, NC       Coal                 35          100%         35.0      CP&L*
Lumberton...............  Lumberton, NC           Coal                 35          100          35.0      CP&L*
Kenansville.............  Kenansville, NC         Coal                 35          100          35.0      CP&L*
Roxboro.................  Roxboro, NC             Coal                 60          100          60.0      CP&L*
Southport...............  Southport, NC           Coal                120          100         120.0      CP&L*
Hopewell................  Hopewell, VA            Coal                120         50.0          60.0      Virginia Power
Portsmouth..............  Portsmouth, VA          Coal                120          100         120.0      Virginia Power
Rocky Mount.............  Rocky Mount, NC         Coal                120          100         120.0      Virginia Power
Ringgold................  Ringgold, PA            Gas                15.5          100          15.5      Pennsylvania Electric
                                                                                                            Company
Richmond................  Richmond, VA            Coal                240          100         240.0      Virginia Power
Birchwood...............  King George, VA         Coal                240         50.0         120.0      Virginia Power
Cottage Grove...........  Cottage Grove, MN       Gas                 245         73.2         179.3      Northern States Power
                                                                                                            Company
Whitewater..............  Whitewater, WI          Gas                 245         74.2         181.8      Wisconsin Electric
                                                                                                            Power Corporation
Logan...................  Logan Township, NJ      Coal                218         50.0         109.0      Atlantic City Electric
Northampton.............  Northampton County, PA  Waste coal          110         50.0          55.0      Metropolitan Edison
Indiantown..............  Martin County, FL       Coal                380         50.0         190.0      Florida Power & Light
Carneys Point...........  Carneys Point, NJ       Coal                262         10.0          26.2      Atlantic City Electric
Panther Creek...........  Carbon County, PA       Waste coal           83         12.2          10.1      Metropolitan Edison
                          Scrubgrass Township,
Scrubgrass..............  PA                      Waste coal           85         20.0          17.0      Pennsylvania Electric
Selkirk.................  Albany, NY              Gas                 396          5.1          20.2      Con Edison & Niagara
                                                                                                            Mohawk
Cedar Bay...............  Jacksonville, FL        Coal                260         16.0          41.6      Florida Power & Light
Mass Power..............  Springfield, MA         Gas                 258          1.7           4.4      Boston Edison
Gilberton...............  Frackville, PA          Waste coal           82         19.6          16.1      Pennsylvania Power &
                                                                                                            Light
Pittsfield..............  Pittsfield, MA          Gas                 173         10.9          18.9      New England Power
Morgantown..............  Morgantown, WV          Coal/Waste Coal      62         15.0           9.3      Monongahela Power
Iroquois Gas              Long Island, NY to      --                   --          0.5            --      --
  Transmission System...  Waddington, NY
</TABLE>

---------------

* Commonly-used acronym for Carolina Power & Light Company

DESCRIPTION OF FACILITIES IN WHICH WE OWN A SIGNIFICANT ECONOMIC INTEREST

  Elizabethtown, Lumberton and Kenansville, North Carolina Facilities

     Our subsidiary, Cogentrix Eastern Carolina Corporation, owns and operates
three 35-megawatt stoker coal-fired cogeneration plants in Elizabethtown,
Lumberton and Kenansville, North Carolina.

     The Elizabethtown, Lumberton and Kenansville facilities sell electricity to
CP&L under separate power sales agreements, which were amended effective in
September 1996. The power sales agreements for the Elizabethtown and Lumberton
facilities expire in November 2000, and the power sales agreement for the
Kenansville facility has an initial term expiring in September 2001. Each of the
facilities may operate at a

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<PAGE>   10

declared production capability of up to approximately 33 megawatts. Another
subsidiary, Cogentrix, Inc., has guaranteed the performance of CECC under the
power sales agreements. Alamac Knit Fabrics, Inc. purchases steam for its
apparel fabrics division mills from the Lumberton facility and the Elizabethtown
facility under separate steam sales agreements. Guilford Mills, Inc. purchases
steam from the Kenansville facility for use in its textile manufacturing plant.

     Each of the power sales agreements provides that in the event of a
termination prior to the expiration of the initial term of the power sales
agreements, our project subsidiary must pay CP&L a termination charge. In the
event of a material breach by the utility, our project subsidiary may terminate
the power sales agreement prior to its expiration without incurring the
termination charge. The termination charge is an amount equal to the excess paid
for capacity and energy over what would have been paid to our project subsidiary
under the state utilities commission's published rates plus interest.

     If the average production capability or electricity generated or made
available during any 12-month period falls below 80% of the established contract
level, a special charge will be imposed by CP&L equal to a percentage of the
termination charge described above. In addition, if our project subsidiary
desires to terminate the power sales agreement prior to its expiration and a
substitute operator satisfactory to the utility is not secured, our project
subsidiary must pay to the utility the termination charge described above plus
an amount equal to the depreciated installed cost of the interconnection
facilities relating to the plant.

  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, which
are owned by another wholly-owned project subsidiary of Cogentrix Energy.

     The Roxboro and Southport facilities sell electricity under separate power
sales agreements, each having an initial term expiring 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 Archer-Daniels-Midland
Company purchases steam for its pharmaceutical and chemical manufacturing
company from the Southport facility.

     Each of the power sales agreements provides 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:

     - the depreciated installed cost of the interconnection facilities relating
       to the plant

     - the cost incurred by the utility to replace the production capability
       provided by the Roxboro or Southport facility in excess of the fixed
       payments which would have been made to our project subsidiary for the
       Roxboro or Southport facility

     - a carrying charge equal to the overall pretax cost of capital allowed to
       the utility by the retail rate order of the state utilities commission in
       effect during the time the energy credits were received.

  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 Edison Mission Energy.

     The Hopewell facility provides declared production capability of up to 92.5
megawatts to Virginia Power under a power sales agreement which 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 Virginia Power,
the project partnership must pay a penalty to Virginia Power. The amount of the
penalty is the difference between
                                       10
<PAGE>   11

payments for production capability already made and those that would have been
allowable under the applicable "avoided cost" schedules of the utility plus
interest. Allied-Signal Corporation purchases steam from the Hopewell facility.

  Portsmouth, Virginia Facility

     Our facility located in Portsmouth, Virginia is a 120-megawatt stoker
coal-fired cogeneration facility. The Portsmouth facility provides Virginia
Power declared production capability of up to 115 megawatts under a power sales
agreement which 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
Virginia Power, then our project subsidiary must pay a penalty to 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 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 Virginia Power, the Rocky Mount facility
provides declared production capability of 115.5 megawatts of electricity for an
initial term expiring in October 2015. In addition, steam from the Rocky Mount
facility is sold to Abbott Laboratories.

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

     If a disallowance event occurs during the period from 1998 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:

     - Projected reduction in cash flows from 2009 through 2013 as a result of
       the disallowance of payments made by the utility and,

     - The amount of our project subsidiary's debt outstanding at September 30,
       2008.

     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.

                                       11
<PAGE>   12

  Ringgold, Pennsylvania Facility

     Our facility located in Ringgold, Pennsylvania, is a 15.5-megawatt
gas-fired cogeneration facility using an internal combustion engine fueled
primarily by natural gas. Pennsylvania Electric Company purchases energy from
the facility. Under the power sales agreement, the failure of our facility to
generate and sell electricity throughout the term of the agreement at an annual
average level which is at least equal to 85% of the average output achieved
during a rolling three-year period of operation would result in the payment of a
penalty.

     In January 1998, we signed an agreement with Pennsylvania Electric Company
to terminate this facility's power purchase agreement. This termination
agreement was the result of a request for proposals from the utility to buy-back
or restructure power sales agreements issued to all major operating independent
power projects in its territory in April 1997. The termination agreement
provides for a payment to our project subsidiary of approximately $20.4 million,
which will be sufficient to retire all of the project subsidiary's outstanding
debt. The buy-back of the power purchase agreement is subject to the issuance of
a satisfactory final order by the Pennsylvania Public Utility Commission
granting Pennsylvania Electric Company the authority to fully recover from its
customers the consideration paid under the buyout agreement. We do not expect
the termination of this facility's power purchase agreement, if it occurs, to
have an adverse impact on our consolidated results of operations or financial
position.

     The Ringgold facility provides hot water to a 10-acre greenhouse owned by
our project subsidiary which is leased to and operated by Village Farms, L.P.
The lease has a ten-year term, which may be extended with our consent.

  Richmond, Virginia Facility

     Our 240-megawatt stoker coal-fired cogeneration plant in Richmond, Virginia
provides 209 megawatts of declared production capability to 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 Virginia Power from recovering from its customers
payments made by 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 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 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 Virginia Power.
Our project subsidiary has letters of credit in favor of Virginia Power to
secure its obligations to perform under the power sales agreements.

     Our project subsidiary purchased one of the power sales agreements from WV
Hydro, Inc. In connection with the purchase and in consideration of certain
consulting arrangements, our subsidiary has continuing obligations to make
payments to an affiliate of WV Hydro, in an aggregate amount ranging from
$250,000 to $750,000, each year through 2003, from excess facility cash flow. If
excess facility cash flow for any year is insufficient to pay the $250,000
minimum amount, the deficiency will be carried forward and is payable from
excess facility cash flow, if any, in future years. In addition, our subsidiary
is obligated to pay an amount ranging from 3 to 3.5 percent of the net proceeds
payable to our subsidiary upon any sale, disposition or refinancing of the
Richmond facility after payment of senior and subordinated project financing
debt and expenses.

                                       12
<PAGE>   13

  Birchwood, Virginia Facility

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

     The Birchwood facility provides up to 202 megawatts of declared production
capability to Virginia Power under a power sales agreement which expires in
2021. The power sales agreement provides that in the event the state utilities
commission prohibits Virginia Power from recovering from its customers payments
made by Virginia Power to our project subsidiary, 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 Virginia Power with interest.

     If this facility is unable to operate within the parameters established by
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 Virginia
Power. The partnership has posted a letter of credit in favor of Virginia Power
to secure its obligations to perform under the power sales agreement.

  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 measured at summer conditions and
262 megawatts of declared production capability measured at winter conditions
under a power sales agreement which expires in 2027. Fixed payments are subject
to adjustment on the basis of performance-based factors which 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 Company 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 Company 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 Company 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 Company 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.

                                       13
<PAGE>   14

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

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

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

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

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

  Logan (New Jersey) Facility

     A Delaware limited partnership owns the Logan facility, which is a
218-megawatt pulverized coal-fired cogeneration generating plant located on the
Delaware River in Logan Township, New Jersey. The partnership leases the Logan
facility to another Delaware limited partnership. An indirect, wholly-owned
subsidiary of Cogentrix, owns a 50% general partnership interest in each of the
first limited partnership and each of the

                                       14
<PAGE>   15

partners of the second limited partnership. An indirect, wholly-owned subsidiary
of PG&E Generating Company ("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 which 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 who make up the deficiency.

     An affiliate of PG&E operates 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 which expires in
2027.

  Northampton (Pennsylvania) Facility

     A Delaware limited partnership owns this 110-megawatt anthracite waste
coal-fired electric generating facility in Northampton County, Pennsylvania. An
indirect, wholly-owned subsidiary of Cogentrix owns a 50% general partnership
interest in this partnership. An indirect, wholly-owned subsidiary of PG&E owns
an aggregate 50% equity interest in the partnership that owns this project,
which consists of a 48% general partnership interest and 2% limited partnership
interest.

     The Northampton facility, which began operation in September 1995, provides
electric energy to Metropolitan Edison Company pursuant to a power sales
agreement which expires in 2020. Capacity in excess of 89 megawatts may be sold
to third parties, but no energy from the Northampton facility may be sold to any
entity other than Metropolitan Edison.

     The Northampton facility is not directly interconnected to Metropolitan
Edison's electric system and accordingly requires an electric utility that is
interconnected with Metropolitan Edison's electric system to transmit the
Northampton facility's output to Metropolitan Edison. Pursuant to a transmission
service agreement (which expires in 2020) with Pennsylvania Power & Light
Company, that utility transmits the Northampton Facility's net electric energy
to Metropolitan Edison's existing electric system.

     In the event the Northampton facility's annual average delivery of
electricity for any year following the commercial operation date during on-peak
hours is less than 85% of the Northampton facility's annual average delivery of
electricity during the on-peak hours for the prior three years, the partnership
that owns the facility is obligated to make a penalty payment to Metropolitan
Edison. During the first 11 years of the power sales agreement commencing with
the commercial operation date, the penalty payment will equal the difference
between 85% of the annual average on-peak electricity delivered in the prior
three years and the actual on-peak electricity delivered in the year to which
the penalty relates times 3.4c per kWh. After the eleventh year of the power
sales agreement, the penalty payment will be calculated as above, except that
the rate of 3.4c per kWh shall be adjusted annually according to changes in the
Gross Domestic Product Implicit Price Deflator.

     Based on its use of waste coal as its primary fuel source, the Federal
Energy Regulatory Commission has certified the Northampton facility as a
"qualifying small power production facility".

     An affiliate of PG&E operates and maintains the Northampton facility
pursuant to an operation and maintenance agreement with an initial term expiring
in 2020. PG&E provides management and administration services for the
Northampton facility pursuant to a management services agreement with an initial
term expiring in 2020.

                                       15
<PAGE>   16

     In addition to the partners' original equity contributions to the
partnership that owns the Northampton facility, the partners have posted letters
of credit or corporate guarantees in an aggregate amount of $9 million as a
standby equity commitment to be used for certain fuel-related costs. They have
also posted a letter of credit in the amount of $2.2 million as a standby equity
commitment to be used solely to establish the bank debt service reserve fund for
the exclusive benefit of the banks. Cogentrix provides letters of credit or
corporate guarantees for 50% of those standby equity commitments.

  Indiantown (Florida) Facility

     A Delaware limited partnership owns this 380-megawatt pulverized coal-fired
cogeneration facility located in Martin County, Florida. An entity controlled by
PG&E owns a 50% general partnership interest in the partnership, and we own a
50% general partnership interest. The Indiantown facility began operation in
December 1995 and sells steam to Caulkins Indiantown Citrus Company.

     The Indiantown facility provides 330 megawatts of declared production
capability to Florida Power & Light Company under a power sales agreement which
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, which provides that if Florida Power & Light at
any time is denied authorization to recover from its customers any payments to
be made under the power sales agreement, Florida Power & Light may, in its sole
discretion, adjust payments under the power sales agreement to the amount it is
authorized to recover from its customers. The utility may also require the
partnership that owns the facility to return payments subsequently disallowed by
the regulatory agency. If the obligations of Florida Power & Light and the
partnership that owns the facility are materially altered due to the operation
of this provision in the agreement, the partnership may terminate the power
sales agreement upon 60 days' notice. The partnership and Florida Power & Light
must then in good faith attempt to negotiate a new power sales agreement or any
agreement for transmission of the Indiantown facility's capacity and energy to
another investor-owned, municipal, or cooperative electric utility
interconnected with Florida Power & Light in Florida.

     An affiliate of PG&E provides operation and maintenance services for the
Indiantown facility pursuant to an operating agreement which expires in 2025.
PG&E manages and administers the business of the partnership that owns the
facility pursuant to a management service agreement which expires in 2029.

  Carneys Point (New Jersey) Facility

     A Delaware limited partnership owns this 262-megawatt pulverized coal-fired
cogeneration facility located within the grounds of the DuPont Chamber Works, a
chemical complex in Carneys Point, New Jersey. The partnership leases the
Carneys Point facility to a partnership of wholly-owned subsidiaries of PG&E.
Lease payments are structured to equal project cash flow, and the lessee
partnership derives no net cash flow or benefit from the lease. We own a 10%
general partnership interest in the limited partnership that owns the facility.
The other general partner is an indirect, wholly-owned subsidiary of PG&E, which
owns a 50% general partnership interest. The sole limited partner is an
indirect, wholly-owned subsidiary of General Electric Capital Corporation, which
owns a 40% limited partnership interest.

     The Carneys Point facility began operation in March 1994. The facility
provides Atlantic City Electric Company with 187.6 megawatts in the summer
months and 173.2 megawatts in the winter months for an annual average of 180.4
megawatts. If the actual available production capability falls below 95% of the
respective production capability requirement for the winter or summer period,
the partnership that owns the facility must make a deficiency payment to the
utility until actual production capability for such period reaches 95% of the
production capability requirements for the period.

                                       16
<PAGE>   17

     Under an energy services agreement, the Carneys Point facility sells steam
and up to 40 megawatts of electricity to DuPont. The Carneys Point facility has
the capability to sell an average of approximately 30 megawatts of excess
production capability and energy to third parties.

     An affiliate of PG&E operates the Carneys Point facility under an operation
and maintenance agreement with an initial term expiring in 2004. PG&E provides
management services for the facility pursuant to a management services agreement
with a term expiring in 2018.

PRINCIPAL CUSTOMERS

     Electric utility customers accounting for more than ten percent of our
consolidated revenue for the fiscal years ended December 31, 1999, 1998 and 1997
were as follows:

<TABLE>
<CAPTION>
                                                          FISCAL YEAR ENDED DECEMBER 31,
                                                          -------------------------------
                                                          1999         1998         1997
                                                          -----        -----        -----
<S>                                                       <C>          <C>          <C>
CP&L....................................................   17%          19%          22%
Virginia Power..........................................   47           50           64
</TABLE>

     As a result of our recent growth, our future operations will be more
diverse with regard to both geography and fuel source and less dependent on any
single project or customer.

REGULATION

     Our plants 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, types of fuel utilized, the type of energy produced and power
plant ownership. 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 over
non-utility owned power plants. Power plants also are subject to laws and
regulations governing environmental emissions and other substances produced by a
plant, along with the geographical location, zoning, land use and operation of a
plant. Applicable federal environmental laws typically have state and local
enforcement and implementation provisions. These environmental laws and
regulations generally require that a wide variety of permits and other approvals
be obtained before construction or operation of a power plant commences and that
the power plant operates in compliance with them. We strive to comply with all
environmental laws, regulations, permits and licenses but, despite such efforts,
at times we have been in non-compliance.

  Energy Regulations

     QFS UNDER THE PUBLIC UTILITY REGULATORY POLICIES ACT OF 1978.  All of our
current operating facilities are classified as a qualifying facility ("QF")
under the Public Utility Regulatory Policies Act of 1978 ("PURPA"). QFs are
relieved of compliance with extensive federal, state and local regulations that
control the development, financial structure and operation of power plants and
cost-of-service based ratemaking to determine the prices at which electric
generating facilities sell energy. In order 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. A QF utilizing oil or natural gas as fuel also 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 must not be
controlled or more than 50% owned by an electric utility or by an electric
utility holding company, or a subsidiary of either or any combination thereof.

     PURPA exempts QFs from the Public Utility Holding Company Act of 1935
("PUHCA"), most provisions of the Federal Power Act (the "FPA") and, except
under limited circumstances, state rate and financial regulations. These
exemptions are important to us and our competitors.

                                       17
<PAGE>   18

     In the absence of a power sales agreement, regulations adopted by the
Federal Energy Regulatory Commission ("FERC") require utilities to purchase
electricity generated by QFs at a price based on the purchasing utility's full
"avoided cost," and that the utility sell back-up power to the QF on a non-
discriminatory basis. Avoided costs are the incremental costs to a utility of
electric energy or capacity, or both, which, but for the purchase from QFs, the
utility would generate for itself or purchase from another source. Due to
increasing competition for utility contracts, the current practice is for most
power sales agreements to be awarded below avoided cost.

     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 which 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
could 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,
in such event, would result in Cogentrix Energy inadvertently becoming a public
utility holding company. 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 nonqualifying facility. If loss
of QF status were threatened for a facility, we could avoid holding company
status and thereby protect the QF status of our other facilities by applying to
the FERC to obtain exempt wholesale generator ("EWG") status for the owner of
the nonqualifying facility. See "-EWGs under the Energy Policy Act of 1992"
herein. 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.

     EWGS UNDER THE ENERGY POLICY ACT OF 1992.  The passage of the Energy Policy
Act has significantly expanded the options available to independent power
producers with respect to their regulatory status. In addition to or in lieu of
QF status, an independent power producer selling exclusively at wholesale now
can also apply to the FERC to be granted status as an EWG. Except for existing
cost-of-service based facilities for which state consents are required, any
owner of a facility may apply for status as an EWG. An EWG, like a QF, is exempt
from regulation under PUHCA. However, EWG status does not exempt a facility from
FERC and state public utility commission ("PUC") regulatory reviews, which may
be more expansive than those applicable to QFs. Several of Cogentrix Energy's
facilities, which are QFs, have also been determined to be EWGs. In addition,
several project subsidiaries developing new generating facilities have also been
determined to be EWGs.

     FOREIGN INVESTMENTS UNDER THE ENERGY POLICY ACT.  The Energy Policy Act has
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 the Energy Policy Act provide that a domestic company
making such an investment may avoid "holding company" status or other regulation
under PUHCA, if the foreign enterprise obtains EWG status or files a notice with
the Securities and Exchange Commission that it is a foreign utility company
("FUCO").

     PUHCA.  Under PUHCA, any entity owning or controlling ten percent or more
of the voting securities of a "public utility company" is a "holding company"
and is subject to registration with the Securities and Exchange Commission and
regulation under PUHCA, unless eligible for an exemption. Under the Energy
Policy Act and PURPA, EWGs, FUCOs, and owners and operators of QFs are deemed
not to be public utility companies under PUHCA. Momentum is growing in Congress
for the repeal of PUHCA, as more legislators adopt the view that this statute
has outlived its purpose. Elimination of PUHCA would enable more companies to
consider owning generating and transmission 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.

                                       18
<PAGE>   19

     FPA.  The FPA grants the FERC exclusive rate-making jurisdiction over
wholesale sales of electricity in interstate commerce, including ongoing as well
as initial rate jurisdiction, which enables the FERC to revoke or modify
previously approved rates. While QFs under PURPA typically are exempt from the
traditional rate-making and certain other provisions of the FPA, projects not
qualifying for QF status, for example, most EWGs, are subject to the FPA and to
FERC rate making jurisdiction. Power marketers are also subject to FERC review
of their wholesale rates, and to FERC oversight of various business dealings
such as corporate reorganizations. Pursuant to the FPA, our power marketing
subsidiary has filed its wholesale electric power rates with the FERC and
obtained authorization to sell electric power at rates set by supply and demand
in the marketplace. In addition, the Logan facility and certain other facilities
in which Cogentrix Energy owns a small interest have filed their rates with the
FERC and obtained authorization to sell all of their power pursuant to those
rates. Several of our projects under development have also filed and obtained
from FERC market-based rates for sales of power from these facilities.

     STATE REGULATION.  PUCs regulate retail rates of electric utilities and, in
many states, power sales agreements from independent power producers. In
addition, states have been delegated the authority to determine utilities'
avoided costs under PURPA. PUCs often will pre-approve agreements with prices
that do 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 will permit utilities
to "pass through" expenses associated with a power sales agreement with an
independent power producer. In addition, retail sales of electricity or steam by
an independent power producer may be subject to PUC regulation, depending on
state law.

     EWGs are 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. Many 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. Federal legislation that would require states to permit retail
competition is also being given serious consideration. 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 and EWGs, many of which are
considered to be overpriced. State commissions are also encouraging efforts by
utilities to buy out or buy down such contracts.

     PROPOSED LEGISLATION.  In addition to federal legislative initiatives, the
state commissions or state legislatures of many 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.

                                       19
<PAGE>   20

     TRANSMISSION AND WHEELING.  Under the FPA, the FERC regulates the rates,
terms and conditions for electricity transmission in interstate commerce. The
FERC's authority under the FPA to require electric utilities to provide
transmission service to QFs and EWGs was significantly expanded by the Energy
Policy Act. Except when market factors such as an exceptional site or power
sales opportunity warrant it, we generally attempt to site our facilities within
the utility customer's service area, and thus avoid the need to utilize
wheeling. The new provisions of the Energy Policy Act, however, and actions
taken by the FERC under the FPA have improved transmission access and pricing
for independent power producers like us.

     In April 1996, the 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. However, many
utilities are seeking permission from the FERC to recover for "stranded
investment" through add-ons to their transmission rates. To the extent that the
FERC permits such charges, the cost of transmission may be too high on some
systems to be of practical use to wholesale sellers like Cogentrix. Therefore,
the full value of Order 888 remains to be determined.

     The FERC is also encouraging the voluntary restructuring of transmission
operations through the use of independent system operators and regional
transmission groups. Such entities may create efficiencies for traditional
utilities, but are not likely to have a substantial impact on power developers
and power marketers like Cogentrix.

  Environmental Regulations -- United States

     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 becomes implemented and
new laws are enacted. Accordingly, we plan to continue a strong emphasis on
implementation of environmental standards and procedures at the facilities we
operate and at our other facilities to minimize the environmental impact of
energy generation at these facilities.

     CLEAN AIR ACT.  In late 1990, Congress passed the Clean Air Act Amendments
of 1990 (the "1990 Amendments") which affect existing facilities as well as new
project development. The original Clean Air Act of 1970 set guidelines for
emissions standards for major pollutants from newly-built sources. All of the
facilities we operate are in compliance with federal performance standards
mandated for such facilities under the Clean Air Act and the 1990 Amendments.
The 1990 Amendments attempt to reduce emissions from existing sources --
particularly large older facilities that were exempted from certain regulations
under the original Clean Air Act.

     The 1990 Amendments create a marketable commodity called a sulfur dioxide
("SO(2)") "allowance." All non-exempt facilities over 25 megawatts that emit
SO(2), including independent power plants, must obtain allowances in order to
operate after 1999. Each allowance gives the owner the right to emit one ton of
SO(2). The 1990 Amendments exempt from the SO(2) allowance provisions all
independent power projects which 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. In the future, the facilities we
expect to develop will continue to rely on "clean low sulfur coal," with flue
gas desulfurization technology or natural gas technology. We believe that the
additional costs of obtaining the number of allowances needed for future
projects should not materially affect our ability to develop such projects.

                                       20
<PAGE>   21

     The 1990 Amendments also contain other provisions that could affect our
projects. Provisions dealing with geographical areas the EPA has designated as
in "nonattainment" with national ambient air quality standards require that
existing sources of air pollutants in a nonattainment area be retrofit with
reasonably available control technology ("RACT") for all pollutants for which an
area is designated nonattainment. The technology currently installed at the
plants we operate should uniformly meet or exceed RACT for those pollutants. The
nonattainment provisions also require that each new or expanded source of air
pollutants in designated 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 and
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.
Continuous emission monitoring systems may need to be upgraded at some
facilities while the permit fees will increase operating expenses. The costs of
applying for and obtaining operating air permits are not anticipated to be
significant.

     The hazardous air pollutant provisions of the 1990 Amendments presently
exclude electric steam generating facilities, such as our facilities. Studies of
the emissions from such facilities have been submitted to Congress. Until
Congress either amends the Clean Air Act further or the EPA promulgates
regulations, the federal hazardous air pollutants emissions restrictions, which
will be applied to our facilities and other electric steam generating
facilities, will remain uncertain.

     In July 1997, the EPA promulgated more restrictive ambient air quality
standards for ozone and for particulate matter: less than 25 microns in diameter
-- PM-2.5. These new standards will likely increase the number of nonattainment
areas for both ozone and PM-2.5. If our facilities are in these new
nonattainment areas, further emission reduction requirements could result in the
installation of additional control technology. In May 1999, the D.C. Circuit
Court of Appeals remanded these standards. However, we will continue to track
these standards and the potential impact on us.

     In addition, the Ozone Transport Assessment Group ("OTAG"), composed of
state and local air regulatory officials from the 37 Eastern states, has
recommended additional NO(x) emission reductions that go beyond current federal
standards. These recommendations include reductions from utility and industrial
boilers. In the fall of 1998, the EPA adopted regulations requiring revisions to
state implementation plans ("SIPs"). These regulations implement some of the
OTAG's recommendations and go beyond some of the OTAG's recommendations for
reductions in NO(x) emissions. As a result of these more stringent NO(x)
emission standards, we may be required to install additional NO(x) emission
control technologies and/or obtain allowances from other emitters. We will
continue to monitor the potential effects this proposed regulation will have on
Cogentrix.

     In December 1999, the EPA issued a final rule requiring reductions of NOx
emissions from 392 generating and other facilities in 12 Eastern and Midwestern
states, including North Carolina and Virginia, by May of 2003. This rule
responds to petitions by Northeastern States under CAA Section 126 for controls
on upwind NOx emission sources, which the states demonstrated prevents them from
attaining the ozone ambient standard. The Section 126 rule is an alternative to
the NOx SIP-Call rule and is very similar in structure. We are considering all
options in complying with this rule including installation of control equipment
and/or purchasing of NOx 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

                                       21
<PAGE>   22

pollution. This rule may effectively make emission limits previously established
for many air pollution sources, including ours, more stringent.

     The Kyoto Protocol regarding greenhouse gas emissions and global warming
was signed by the U.S., committing to significant reductions in greenhouse gas
emissions. The U.S. Senate must ratify the agreement for the protocol to take
effect. The Clinton Administration has proposed a package of legislative and
administrative policies to curb greenhouse gases, none of which are affected by
the need for Senate ratification. Management believes that none of these
policies will have a material effect on the consolidated results of operations
or financial position of Cogentrix. Future initiatives on this issue and the
effects on Cogentrix 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 which can be used to modify a
permit at anytime. Several of the facilities we operate have either recently
gone through permit renewal or will be renewed within the next few years. Based
upon recent renewals, we do not anticipate more stringent monitoring
requirements for any of the facilities we operate. We believe that we are in
material compliance with applicable discharge requirements under the Clean Water
Act.

     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
or pay for such actions. PRPs are broadly defined under CERCLA to include past
and present owners and operators of, as well as generators of wastes sent to a
site. At present, we are not subject to liability for any Superfund matters and
take measures to assure that CERCLA will not apply to properties we own or
lease. However, we do generate certain wastes in the operation of our plants,
including small amounts of hazardous wastes, and send certain wastes to third-
party waste disposal sites. As a result, there can be no assurance that we will
not incur liability under CERCLA in the future.

     RESOURCE CONSERVATION AND RECOVERY ACT ("RCRA").  RCRA regulates the
generation, treatment, storage, handling, transportation and disposal of
hazardous wastes. We are exempt from the solid waste requirements under RCRA
regarding coal combustion by-products. We are classified as a conditionally
exempt small quantity generator of hazardous wastes at all of our facilities. 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 which 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.
                                       22
<PAGE>   23

     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 which 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, 1999, we employed 524 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 lease our principal executive office,
a single 61,024 square foot building, located at 9405 Arrowpoint Boulevard in
Charlotte, North Carolina. We lease the building and related land from a
partnership comprised of four shareholders of Cogentrix Energy. The building
lease has an initial term ending in 2004, with optional renewals through 2047.
The term of the land lease extends through 2047. See "Certain Relationships and
Related Transactions -- Leases and Real Property Transactions."

     We also lease office space in Prince George, Virginia 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 of coal combustion by-products for use 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 and after consultations with various counsel
retained to represent the subsidiary in the defense of such claims - 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.

                                       23
<PAGE>   24

                                    PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SHAREHOLDER MATTERS

(a) Market Information -- There is no established market for our common stock,
    which is closely held.

(b) Principal Shareholders -- All of the issued and outstanding shares of common
    stock of Cogentrix Energy are beneficially owned by the six persons listed
    in Item 12 of this report.

(c) Dividends -- For the year ended December 31, 1999, our board of directors
    declared a dividend on our outstanding common stock of $8.7 million, which
    was paid in March 2000. Our board of directors declared a dividend on our
    outstanding common stock of $7.4 million for the fiscal year ended December
    31, 1998, which was paid in March 1999. The board of directors has adopted a
    policy, which is subject to change at any time, of maintaining 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 under
    which Cogentrix Energy has senior debt outstanding and the corporate credit
    facility agreement, our ability to pay dividends and make other
    distributions to our shareholders is restricted.

                                       24
<PAGE>   25

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, 1999, 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, 1999 set forth below has
been derived from our consolidated financial statements.

<TABLE>
<CAPTION>
                                                         YEARS ENDED DECEMBER 31,
                                          -------------------------------------------------------
                                            1999       1998       1997       1996        1995
                                          --------   --------   --------   --------   -----------
                                                          (DOLLARS IN THOUSANDS)      (UNAUDITED)
<S>                                       <C>        <C>        <C>        <C>        <C>
Operating revenue:
     Electric...........................  $294,185   $293,083   $307,104   $340,681    $361,694
     Steam..............................    25,236     25,043     26,123     28,987      23,328
     Lease..............................    44,697     34,715         --         --          --
     Service revenue under capital
       leases...........................    43,888     34,470         --         --          --
     Income from unconsolidated
       investments in power projects....    25,464      6,474      1,412      3,408          --
     Other..............................    14,093     14,908     15,275     15,769      12,655
                                          --------   --------   --------   --------    --------
          Total operating revenue.......   447,563    408,693    349,914    388,845     397,677
                                          --------   --------   --------   --------    --------
Operating expenses:
     Operating costs....................   195,142    185,567    190,098    232,199     238,261
     General, administrative and
       development......................    39,014     36,490     41,650     31,245      28,853
     Depreciation and amortization......    43,713     42,535     41,844     37,455      38,848
     Loss on impairment and cost of
       removal of cogeneration
       facilities.......................        --         --         --     65,628          --
                                          --------   --------   --------   --------    --------
          Total operating expenses......   277,869    264,592    273,592    366,527     305,962
                                          --------   --------   --------   --------    --------
Operating income........................   169,694    144,101     76,322     22,318      91,715
Other income (expense):
     Interest expense...................   (94,956)   (74,949)   (53,864)   (56,950)    (59,362)
     Investment and other income........    11,213      9,226      9,789     10,942       8,232
     Equity in net income (loss) of
       affiliates, net..................      (208)    (3,274)    (1,538)    (2,135)        109
Minority interest in income.............   (14,752)   (12,458)    (4,672)    (5,621)     (3,558)
                                          --------   --------   --------   --------    --------
Income (loss) before income taxes and
  extraordinary gain (loss).............    70,991     62,646     26,037    (31,446)     37,136
Benefit (provision) for income taxes....   (27,576)   (24,914)    (9,754)    11,273     (13,783)
                                          --------   --------   --------   --------    --------
Income (loss) before extraordinary
  loss..................................    43,415     37,732     16,283    (20,173)     23,353
Extraordinary loss on early
  extinguishment of debt, net...........        --       (743)    (1,502)      (703)         --
                                          --------   --------   --------   --------    --------
Net income (loss).......................  $ 43,415   $ 36,989   $ 14,781   $(20,876)   $ 23,353
                                          ========   ========   ========   ========    ========
</TABLE>

OTHER FINANCIAL RATIO DATA

     Set forth below are other financial data and ratios for the periods
indicated (in thousands, except ratio data):

<TABLE>
<CAPTION>
                                                              YEARS ENDED DECEMBER 31,
                                                              ------------------------
                                                                1999            1998
                                                              --------        --------
<S>                                                           <C>             <C>
Parent EBITDA...............................................  $96,982         $63,884
Parent Fixed Charges........................................  $32,548         $14,217
Parent EBITDA/Parent Fixed Charges..........................     2.98            4.49
</TABLE>

                                       25
<PAGE>   26

     Parent EBITDA represents cash flow to Cogentrix Energy prior to debt
service and income taxes of Cogentrix Energy. Parent Fixed Charges include cash
payments made by Cogentrix Energy related to outstanding indebtedness of
Cogentrix Energy and the cost of funds associated with Cogentrix Energy's
guarantees of some of its subsidiaries' indebtedness. Our management believes
Parent EBITDA is a useful measure of Cogentrix Energy's ability to service debt.
Parent EBITDA should not be construed, however, as an alternative to operating
income or to cash flows from operating activities.

<TABLE>
<CAPTION>
                                                              AS OF DECEMBER 31,
                                           --------------------------------------------------------
                                              1999         1998        1997       1996       1995
                                           ----------   ----------   --------   --------   --------
<S>                                        <C>          <C>          <C>        <C>        <C>
BALANCE SHEET DATA:
Total Assets.............................  $1,998,386   $1,499,851   $822,974   $865,941   $914,136
                                           ==========   ==========   ========   ========   ========
Project financing debt (1)...............  $1,204,983   $  877,653   $567,705   $620,885   $639,823
                                           ==========   ==========   ========   ========   ========
Parent debt (2)..........................  $  355,000   $  355,000   $100,000   $100,000   $100,000
                                           ==========   ==========   ========   ========   ========
Total shareholders' equity...............  $  121,451   $   87,863   $ 58,298   $ 50,631   $ 75,891
                                           ==========   ==========   ========   ========   ========
</TABLE>

---------------

(1) Project financing debt with respect to each of our facilities is
    "substantially non-recourse" to Cogentrix Energy and its other project
    subsidiaries. For a discussion of the term "substantially non-recourse," see
    "Business -- Project Agreements, Financing and Operating Arrangements for
    Our Facilities -- Project Financing" herein.
(2) Parent debt represents obligations of Cogentrix Energy only and does not
    include non-recourse obligations of our project subsidiaries.

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

 Effect of Recent Power Purchase Agreement Restructurings on our Revenues,
 Expenses and Cash Flow

     Each of our electric generating facilities in operation produces
electricity for sale to a utility and thermal energy for sale to an industrial
user. The electricity and thermal energy generated by these facilities are
typically sold under long-term power or steam sales agreements.

     A number of the generating facilities we originally developed sold
electricity under long-term contracts that obligated the electric utility to
purchase all electricity generated by the facility. We subsequently negotiated
amendments to the majority of these contracts to provide the electric utility
the ability to suspend or reduce its purchases of electricity from each facility
if the electric utility determines the utility can operate its system for a
designated period of time more economically.

     The amended power purchase agreements are structured so that we continue to
receive -- during any period the utility exercises its ability to suspend or
reduce purchases of electricity -- fixed payments that are designed in part to
cover the facility's debt service and its fixed operating costs. These fixed
payments also make up a substantial portion of the profit component of each
power purchase agreement.

                                       26
<PAGE>   27

     When the electric utility exercises its right to suspend or reduce
purchases of electricity from us, we do not receive, or receive only in reduced
amounts, the variable payments for electricity produced that are intended
primarily to cover our variable operating and maintenance costs, as well as our
coal and rail transportation costs. Because we are not producing electricity, or
are producing electricity in reduced amounts, these variable costs are
correspondingly reduced.

     Despite the reduced variable payments we receive when an electric utility
suspends or reduces its purchases of electricity from us, we generally recognize
an increase in cash flows. The increase in cash flows is a result of both the
lower operating and maintenance costs during the period of suspension or
reduction and the amount of the fixed payments the utility must continue to make
during the period.

     The restructuring of these power purchase agreements represents a positive
development both for us and for the electric utilities. Even when the fixed
payments the utilities must make to us are combined with their cost of obtaining
electricity from alternative sources, those payments still represent a
significant reduction from the rates the electric utilities would have paid us
for electricity generated by our facilities had the power purchase agreements
not been restructured.

  Termination Dates of Seven of our Power Sales Agreements

     The power sales agreements at seven of our facilities either terminate in
years 2000 through 2002 or provide for a significant reduction in fixed payments
received under such agreements after 2002. Accordingly, revenues recognized by
us under these power sales agreements will, after 2002, be eliminated or
significantly reduced. Our management believes, however, that our project
subsidiaries and unconsolidated 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. In addition to
restructuring activities in various states, there have also been several
industry restructuring bills introduced in Congress. 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.

  Recent Acquisitions, Development and Other Changes in our Portfolio of
Generating Plants

     Our recent growth has substantially increased our electric production
capability. The acquisition of ownership interests in the Cottage Grove and
Whitewater facilities, whose power sales agreements are accounted for as
"sales-type" capital leases, has resulted in the recognition of lease and
service revenues, as well as cost of services under "sales-type" leases. The
acquisition of ownership interests in twelve electric generating facilities has
significantly impacted the amount of income recognized from unconsolidated power
projects. These acquisitions were financed with debt and as a result, have
impacted the interest expense reported in our results of operations. Our
facilities under construction 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 interest
expense.

                                       27
<PAGE>   28

RESULTS OF OPERATIONS

     The following table sets forth the results of operations and percentage of
total operating revenues represented by the components of operating revenues and
expenses for the years ended December 31, 1999, 1998 and 1997.

<TABLE>
<CAPTION>
                                                           YEAR ENDED DECEMBER 31,
                                              --------------------------------------------------
                                                   1999              1998              1997
                                              --------------    --------------    --------------
<S>                                           <C>        <C>    <C>        <C>    <C>        <C>
Total operating revenues....................  $447,563   100%   $408,693   100%   $349,914   100%
Operating costs.............................   195,142    44     185,567    45     190,098    54
General, administrative and development.....    39,014     9      36,490     9      41,650    12
Depreciation and amortization...............    43,713     9      42,535    11      41,844    12
                                              --------   ---    --------   ---    --------   ---
Operating income............................  $169,694    38%   $144,101    35%   $ 76,322    22%
                                              ========   ===    ========   ===    ========   ===
</TABLE>

  Fiscal Year Ended December 31, 1999 as compared to Fiscal Year Ended December
31, 1998

     Total operating revenues increased 9.5% to $447.6 million for the year
ended December 31, 1999 as compared to $408.7 million for the year ended
December 31, 1998. This increase was primarily attributable to the $19.4 million
increase in lease and service revenue earned under the power sales agreements
for the Cottage Grove and Whitewater facilities in which we acquired our
interests in March, 1998. The increase in operating revenues also relates to a
$19.0 million increase in income from unconsolidated investments in power
projects. This increase was primarily attributable to the purchase of interests
in 12 electric generating facilities in October, 1998. The increase in income
from unconsolidated investments in power projects was also impacted by the
purchase of an additional 40% interest in the Indiantown facility during 1999.
The increase in total operating revenues was partially offset by a decrease in
other operating revenue, due to the recognition of a $4.6 million construction
management fee received in 1998 for the completion of a 248 megawatt, gas-fired
electric generating facility in Clark County, Washington.

     Total operating expenses increased 5.1% to $195.1 million for the year
ended December 31, 1999 as compared to $185.6 million for the year ended
December 31, 1998. This increase was primarily attributable to the $9.9 million
in cost of services incurred by the Cottage Grove and Whitewater facilities,
interests in which we acquired in March, 1998. Total operating expenses also
increased as a result of an increase in fuel expense of $3.4 million associated
with an increase in overall megawatt hours sold to the purchasing utilities at
our plants, the amortization of our fuel litigation settlement with a coal
supplier and an increase in fuel sold to third parties at the Cottage Grove and
Whitewater facilities. The increase in total operating expenses was partially
offset by a $4.6 million decrease in operation and maintenance expenses due to
routine maintenance expenses incurred at several of our facilities during the
year ended December 31, 1998.

     General, administrative, and development expenses increased 6.8% to $39.0
million for the year ended December 31, 1999 as compared to $36.5 million for
the year ended December 31, 1998. This increase is primarily due to an increase
in compensation expense related to an increase in the number of corporate
employees, an increase in incentive compensation expense related to our
increased profitability, and expense related to the buyout of an executive's
participation in an incentive compensation plan. General and administrative
expense was also impacted, to a lesser extent, by an increase in information
system consulting costs resulting from the implementation of various new core
business systems. The increase in general, administrative, and development
expenses was partially offset by the capitalization of development costs related
to certain project development efforts during the year ended December 31, 1999
and a decrease in travel and other development costs related to international
development activity.

     Interest expense increased 26.8% to $95.0 million for the year ended
December 31, 1999 as compared to $74.9 million for the year ended December 31,
1998. Our average long-term debt increased to $1.2 billion, with a weighted
average interest rate of 7.62% for the year ended December 31, 1999 as compared
to average long-term debt of $1.0 billion, with a weighted average interest rate
of 7.25% for the year ended December 31, 1998. The increases in interest expense
and weighted average debt outstanding were related to the inclusion of the
project debt of the Cottage Grove and Whitewater facilities acquired in March,
1998, the issuance of $255

                                       28
<PAGE>   29

million of 8.75% senior notes during the fourth quarter of 1998, and borrowings
incurred during the year under revolving credit facilities at some subsidiaries
related to acquisitions made during the year. The increase in average long-term
debt outstanding was also impacted, to a lesser extent, by an outstanding
construction loan of approximately $70 million in December, 1999, for the
project under construction in Jenks, Oklahoma. The increase in interest expense
was partially offset by a decrease in interest expense at several of our project
subsidiaries resulting from the scheduled repayment of outstanding project
finance debt, and the capitalization of interest costs on projects under
construction.

     The increase in minority interest in income for the year ended December 31,
1999 as compared to the year ended December 31, 1998 related to the inclusion of
a full twelve months of operations for the Cottage Grove and Whitewater
facilities in the year ended December 31, 1999, as compared to only nine months
in the year ended December 31, 1998, and the settlement of the construction
contract on the Whitewater and Cottage Grove facilities.

  Fiscal Year Ended December 31, 1998 as compared to Fiscal Year Ended December
31, 1997

     Total operating revenues increased 16.8% to $408.7 million for the year
ended December 31,1998 as compared to $349.9 million for the year ended December
31, 1997. This increase was primarily attributable to the $69.2 million
aggregate amount of lease revenue and service revenue earned under the power
sales agreements for the Cottage Grove and Whitewater facilities in which we
acquired our interests in March 1998. Operating revenues were also impacted by
an increase in income from unconsolidated investments in power projects. The
increase was primarily the result of the acquisition of ownership interests in
twelve electric generating facilities in October, 1998. We recognized
approximately $2.8 million of revenue, net of premium amortization, related to
these ownership interests. These increases in operating revenues were partially
offset by a net decrease in electric revenue for the year ended December 31,
1998 as compared to the year ended December 31, 1997. This decrease is primarily
the result of a restructuring of power sales agreements at two of our facilities
to give the purchasing utility the right to suspend or reduce purchases of
energy. The decrease in electric revenues was partially offset by an increase in
electric revenue at three of our facilities due to an increase in megawatt hours
sold to the purchasing utilities.

     Our operating costs decreased approximately 2.4% to $185.6 million for the
year ended December 31, 1998 as compared to $190.1 million for the year ended
December 31, 1997. The decrease in operating expenses was primarily the result
of a $38.3 million reduction in fuel expense at two of our facilities resulting
from the restructuring of their power sales agreements. The decrease was also a
result of a decrease in operating costs incurred by ReUse related to third-party
agreements. This decrease was partially offset by the $39.4 million in cost of
services incurred by the Cottage Grove and Whitewater facilities, interests in
which we acquired in March 1998. Operating expenses were also impacted by the
increases in fuel expense at two of our facilities associated with an increase
in megawatt hours sold.

     General, administrative and development expenses for the year ended
December 31, 1998 decreased 12.5% to $36.5 million as compared to $ 41.7 million
for the year ended December 31, 1997. The decrease was primarily the result of
$10.7 million of expense recognized in the year ended December 31, 1997 related
to the restructuring or termination of incentive compensation arrangements for
certain employees, as well as expense incurred related to severance payments to
certain executive officers. The decrease was also due to a general decrease in
salary expense during the year ended December 31, 1998 as a result of a
restructuring we completed in the prior year. This decrease was partially offset
by an increase in incentive compensation expense related to our profit-sharing
plan as a result of the increase in our profitability for the year ended
December 31, 1998, and expenses incurred related to our project development
efforts.

     Interest expense increased 39.1% to $74.9 million for the year ended
December 31, 1998 as compared to $53.9 million for the year ended December 31,
1997. Our average long-term debt increased to $1.0 billion, with a weighted
average interest rate of 7.25%, for the year ended December 31, 1998 as compared
to average long-term debt of $697 million, with a weighted average interest rate
of 7.73%, for the year ended December 31, 1997. The increases in interest
expense and weighted average debt outstanding are related to the inclusion of
the project finance debt of the Cottage Grove and Whitewater facilities acquired
in March

                                       29
<PAGE>   30

1998, and the increase in project finance debt outstanding at the Portsmouth
Facility, which was refinanced in December 1997, and the Hopewell Facility,
which was refinanced in February 1998. The increases also relate to the issuance
of $255 million of 8.75% senior notes in the fourth quarter of 1998 and periodic
borrowings under the corporate credit facility. The increase in interest expense
discussed above was partially offset by a decrease in interest expense at
several of our project subsidiaries due to the scheduled repayment of
outstanding project finance debt.

     The increase in the equity in net loss of affiliates for the year ended
December 31, 1998 relates to an increase in losses recognized by the
partnerships operating tomato greenhouses in the states of New York and Texas.
In December 1998, we entered into an agreement to sell our interests in these
partnerships which resulted in the recognition of a $2.1 million gain included
in investment and other income in the accompanying consolidated statements of
operations.

     The increase in minority interests in income for the year ended December
31, 1998 as compared to the prior year relates to the recognition of the
minority partner's share of earnings in the Cottage Grove and Whitewater
facilities, and an increase in earnings at the Hopewell Facility as a result of
that facility's restructured power sales agreement.

     The extraordinary loss on early extinguishment of debt for the year ended
December 31, 1998 relates to the refinancing of the Hopewell Facility's project
debt in January 1998. The loss consisted of a write-off of the deferred
financing costs on the Hopewell Facility's original project debt and a swap
termination fee on an interest rate swap agreement hedging the original project
debt.

LIQUIDITY AND CAPITAL RESOURCES

     The principal components of operating cash flow for the year ended December
31, 1999 were generated by net income of $43.4 million, increases due to
adjustments for depreciation and amortization of $43.7 million, deferred income
taxes of $23.9 million, minority interest in income, net of dividends of $8.5
million and equity in net income of unconsolidated affiliates, net of dividends,
of $3.6 million which were partially offset by amortization of unearned lease
income, net of minimum lease payments received of $1.6 million and a net $12.5
million use of cash reflecting changes in other working capital assets and
liabilities. Cash flow provided by operating activities of $109.0 million,
proceeds from project finance borrowings of $191.3 million, and $12.2 million of
cash escrows released, were primarily used to purchase property, plant and
equipment additions of $4.3 million, to make investments in affiliates of $76.8
million, to pay deferred financing costs of $9.0 million, to repay project
finance borrowings of $122.2 million, to pay a dividend to common shareholders
of $7.4 million and to fund construction in progress and project development
costs of $60.7 million.

     The principal components of operating cash flow for the year ended December
31, 1998 were net income of $37.0 million, increases due to adjustments for
depreciation and amortization of $42.5 million, deferred income taxes of $14.2
million, a write-off of deferred financing costs of $2.2 million and equity in
net income (loss) of unconsolidated affiliates, net of dividends of $10.2
million, which were partially offset by amortization of unearned lease income,
net of minimum lease payments received of $2.0 million, minority interests in
income, net of dividends, of $14.5 million, a gain on sale of investment in
affiliates of $2.1 million and a net $12.8 million use of cash reflecting
changes in other working capital assets and liabilities. Cash flow provided by
operating activities of $74.7 million, proceeds from borrowings of $384.1
million, proceeds from the sale of marketable securities of $42.1 million, $23.0
million of cash escrows released and cash on hand at the beginning of the year
of $23.6 million were primarily used to acquire interests in facilities of
$155.3 million, purchase property plant and equipment of $7.4 million, make
investments in affiliates of $180.3 million, repay project finance borrowings of
$193.8 million, pay deferred financing costs of $8.6 million and pay a common
stock dividend of $2.1 million.

     Historically, we have financed each facility primarily under financing
arrangements and related documents which generally require 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 interest in that

                                       30
<PAGE>   31

project subsidiary. This type of financing is generally referred to as "project
financing." The project financing debt of our subsidiaries and joint ventures
(aggregating $1.2 billion as of December 31, 1999) is non-recourse to Cogentrix
Energy and its other project subsidiaries, except in connection with certain
transactions where Cogentrix Energy has agreed to certain limited guarantees and
other obligations with respect to such projects. These limited guarantees and
other obligations include agreements for the benefit of the project lenders to
two project subsidiaries to fund cash deficits the projects may experience as a
result of incurring certain costs, subject to an aggregate cap of $40.6 million.

     In addition, Cogentrix Inc., which is an indirect subsidiary of Cogentrix
Energy, has guaranteed two project subsidiaries' obligations to the purchasing
utility under five power sales agreements. Three of these power sales agreements
provide that in the event of early termination that is not for cause, the
project subsidiary must pay the utility a termination charge equal to the excess
paid for capacity and energy over what would have been paid to the utility under
the utility's published five-year capacity credit and variable energy rates plus
interest. The remaining two power sales agreements provide that in the event of
early termination, the project subsidiary must pay the utility the cost of
replacing the electricity from a third party for the remainder of the
agreement's term. 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. If we or our
subsidiary were required to satisfy all of these guarantees and other
obligations or even one or more of the significant ones, it could impair
Cogentrix Energy's ability to service its outstanding debt.

     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 ability of our 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: (a)
debt service payments be current, (b) debt service coverage ratios be met, (c)
all debt service and other reserve accounts be funded at required levels and (d)
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 subsidiary. Management does not believe that such
restrictions or limitations will adversely affect Cogentrix Energy's ability to
meet its debt obligations.

     As of December 31, 1999, we had long-term debt (including the current
portion thereof) of approximately $1.6 billion. With the exception of the $355
million of senior notes currently outstanding, substantially all of such
indebtedness is project financing debt, a large portion of which is non-recourse
to Cogentrix Energy. Future annual maturities of long-term debt range from $54.8
million to $105.9 million in the five-year period ending December 31, 2004. We
believe that our project subsidiaries and the project entities in which we have
an investment will generate sufficient cash flow to pay all required debt
service on the project financing debt and 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 outstanding balances under
the corporate credit facility, the 2004 notes and the 2008 notes and to fund a
significant portion of its development activities and meet its other
obligations. If, as a result of unanticipated events, our ability to generate
cash from operating activities is significantly impaired, we could be required
to curtail our development activities to meet our debt service obligations.

     In December 1997, we renegotiated the project financing arrangements for
our Portsmouth facility. The amended agreements resulted in an extension of the
final maturity date of the loan by three months and an increase in the amount of
commitment provided by the project lenders in the form of a $43.5 million
revolving credit facility. The revolving credit facility is available to be
drawn by the project subsidiary owning the Portsmouth facility at any time for
general corporate purposes, including paying dividends to Cogentrix Energy.
During 1999, the project subsidiary borrowed $20.4 million under the revolving
credit facility and

                                       31
<PAGE>   32

distributed such amount to Cogentrix Energy for purposes of funding a portion of
the purchase price related to the acquisition of a 40% interest in the
Indiantown facility.

     In February 1998, we renegotiated the project financing arrangements for
the Hopewell facility, in which we own a 50% interest. The amended agreements
resulted in a $34.6 million increase in outstanding indebtedness of the project
subsidiary owning and operating the facility, and extended the final maturity
date of the loan by six months. The project subsidiary transferred substantially
all of the additional funds borrowed (net of transaction costs) to its partners.
The distribution received by Cogentrix Energy related to the refinancing was
approximately $16.6 million.

     In March 1998, we acquired from LS Power Corporation an approximate 74%
ownership interest in the Whitewater facility and the Cottage Grove facility.
Each of the Cottage Grove and Whitewater facilities is a 245-megawatt gas-fired,
combined-cycle cogeneration facility. Commercial operations of the facilities
commenced in the last half of calendar 1997. The aggregate acquisition price for
our ownership interests in the Cottage Grove and Whitewater facilities was
$158.0 million. In addition, we pre-funded a $16.7 million distribution to the
previous owners. This distribution represented unused construction contingency
funds and cash flows that were accumulated by the Cottage Grove and Whitewater
facilities prior to January 1, 1998. Cogentrix Energy received a distribution of
$15.7 million in April 1998, and received a distribution of the remaining $1.0
million in 1999. The purchase price was funded with the proceeds of the
corporate credit facility and corporate cash balances.

     In August 1998, we acquired an approximate 52% interest in the Batesville
facility. We have committed to provide an equity contribution to the project
subsidiary of approximately $54 million upon the earliest to occur of (a) the
incurrence of construction costs after all project financing has been expended,
(b) an event of default under the project subsidiary's financing arrangements or
(c) June 30, 2001. This equity commitment is supported by a $54 million letter
of credit, which is provided under the corporate credit facility. We expect the
Batesville facility, which we will operate, to begin operation in summer 2000.
Electricity generated by the Batesville facility will be sold under long-term
power purchase agreements with two investment-grade utilities.

     In October 1998, we acquired Bechtel Generating Company, Inc.'s ownership
interests in 12 electric generating facilities, comprising a net equity interest
of approximately 365 megawatts, and one interstate natural gas pipeline. The
aggregate acquisition price for the Bechtel Acquisition including acquisition
costs was approximately $189.7 million. The purchase price was funded with a
portion of the proceeds from the sale of the 2008 notes.

     On October 29, 1998, we amended and restated the corporate credit facility
to provide for direct advances to, or the issuance of letters of credit for, our
benefit in an amount up to $125 million. The corporate credit facility is
unsecured and imposes covenants on us substantially the same as the covenants
contained in the indentures as well as certain financial condition covenants. We
have used approximately $117 million of the credit availability under the
corporate credit facility for letters of credit issued in connection with the
Bechtel Acquisition, the Batesville Acquisition and the construction of the
Oklahoma Facility. The balance of the commitment 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. Subsequent to December 31, 1999, the
corporate credit facility was amended to provide for $175 million of revolving
credit and to modify the covenants. The revolving credit facility has been
extended through October 2002.

     As a result of a March 1999 arbitration award related to a contract dispute
with a coal supplier, we were obligated to pay the coal supplier approximately
$8 million in 1999. Approximately $3 million of this award relates to the
reduction in purchase quantities for prior periods and approximately $5 million
relates to the reduction in purchase quantities from the date of the award
through the balance of the term of the coal contract, which ends in September
2001. The future reduction in purchase quantities provides a future economic
benefit to our project subsidiary. The amount of damages awarded did not
materially reduce the projected amount of cash flow to Cogentrix Energy for the
current fiscal year and did not, therefore, have a material adverse impact on
Cogentrix Energy's ability to service its outstanding debt.
                                       32
<PAGE>   33

     In June, 1999, we entered into an agreement to purchase an additional 40%
ownership interest in the Indiantown cogeneration facility in a three-phase
transaction. We paid $39.8 million to acquire a 19.9% interest in the facility
in June, 1999, $36.6 million to acquire a 20% interest in the facility in
September, 1999 and $0.2 million to acquire a 0.1% interest in the facility in
November, 1999. We funded the purchase of these interests with proceeds from the
CEA credit facility and the Portsmouth credit facility.

     In September 1999, one of our wholly-owned subsidiaries, Cogentrix Eastern
America, Inc., ("CEA") formed to hold our twelve electric generating facilities
acquired in the Bechtel Acquisition, entered into a $75 million, three-year
revolving credit facility. The commitment under this facility reduces to $67.5
million after one-year and to $60 million after two years. Certain covenants and
financial conditions must be met under this credit facility prior to cash
distributions received by CEA being available for distribution to Cogentrix
Energy. With the closing of this credit facility, our subsidiaries now maintain
revolving credit facilities, which are non-recourse to us, with aggregate
commitments of $143.0 million. As of December 31, 1999, we had $42.6 million
available under these facilities.

     In November 1999, Cottage Grove, Whitewater and the contractor, with the
concurrence of the independent engineer, reached a final agreement regarding the
settlement of all outstanding issues and obligations of Cottage Grove,
Whitewater and the contractor pursuant to the Cottage Grove and Whitewater
construction contracts. The final settlement of the construction contracts
provided for a payment to the contractor of approximately $4,030,000 from funds
available in Cottage Grove's and Whitewater's construction retainage accounts.
The contractor has also agreed to extend various warranty periods and perform
various repairs and inspection. Cottage Grove and Whitewater, in turn,
acknowledged that final acceptance shall have been deemed to have occurred. The
value of the existing letters of credit provided in lieu of cash retainage was
reduced from $11,030,000 to $5,000,000. The remaining value of these letters of
credit will be decreased in stages as the contractor successfully completes the
agreed upon inspections and additional work. The settlement provided for the
release of approximately $9,441,000 of remaining restricted cash from the
construction retainage accounts of Cottage Grove and Whitewater. These funds
were distributed to Cogentrix in November, 1999.

     In December, 1999, we closed a $350 million construction loan with two
banks and commenced construction on an approximate 800 megawatt, combined-cycle,
natural gas-fired generating facility located in Jenks, Oklahoma. We have
committed to provide an equity contribution to the project subsidiary of
approximately $56.9 million upon the earliest to occur of (a) an event of
default under the project subsidiary's financing agreement, (b) the incurrence
of construction costs after all project financing has been expended, or (c) June
24, 2002. The equity contribution is reduced by approximately $8.2 million upon
our receipt of a waste water discharge permit, and further reduced by
contributions made by us once the construction loan proceeds are exhausted. This
equity contribution commitment is supported by a letter of credit, which is
provided under the corporate credit facility. We expect the Oklahoma facility,
which we will operate, to begin operation in June 2002. Electricity generated by
the Oklahoma facility will be sold under a long-term power purchase agreement to
PECO Energy's Power Team.

     In March 2000, we closed a credit facility with a bank and a financial
institution which provides for a $126 million construction loan and a $5 million
debt service reserve letter of credit. Proceeds from the construction loan will
be used to construct an approximate 270 megawatt combined-cycle natural
gas-fired generating facility located in Rathdrum, Idaho. We own a 51% interest
in a partnership that will own this facility and have committed to provide an
equity contribution to the project subsidiary of approximately $16.7 million
upon the earliest to occur of (a) an event of default under the project's
subsidiary's financing agreement, (b) the incurrence of construction costs after
all project financing has been expended, or (c) October 1, 2002. This equity
contribution commitment is supported by a letter of credit, which is provided
under the corporate credit facility. In addition, Cogentrix Energy has agreed to
make additional stand-by equity contributions to cover certain contingent costs
during the construction period capped at $3.6 million. An indirect, wholly-owned
subsidiary of Cogentrix Energy has entered into an engineering, procurement and
construction (EPC) contract with the partnership to construct the Rathdrum
facility. Cogentrix Energy is providing a guarantee supporting the subsidiary's
obligations under the EPC contract. We expect the Rathdrum facility, which we
will operate, to begin operation in the third quarter of 2001. Electricity
generated
                                       33
<PAGE>   34

by the Rathdrum facility will be sold under a long-term power purchase agreement
to Avista Turbine Power, Inc.

     We are in the advanced stages of developing a 300 megawatt electric
generating plant in the Dominican Republic. This project will utilize fuel
oil-fired, combined-cycle technology. We are serving as lead developer in a
partnership with Commonwealth Development Corporation of Great Britain. This
facility will sell electricity under a long-term power purchase agreement with
the CDE supported by a Dominican government guarantee of the payment
obligations. The project is expected to close financing and commence
construction in the second quarter of 2000 with a commencement of operations in
2001. We currently anticipate requiring funds of approximately $50 million for
the purpose of making our equity investment in the Dominican Republic project.
We expect to fund this equity commitment from corporate cash balances.

     We have entered into commitments with a turbine supplier to purchase a
specified number of turbines with specified delivery dates. We have made
approximately $11.2 million in non-refundable deposits related to these
commitments through December 31, 1999. We expect to make additional progress
payments of $82.9 million in 2000, of which approximately $75.8 million would be
repaid or funded from proceeds of financings we anticipate closing.

     For the fiscal year ended December 31, 1999, our board of directors
declared a dividend on the outstanding common stock of $8.7 million, which was
paid in March 2000. 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 under which Cogentrix Energy has senior debt outstanding and
corporate credit facility agreement, our ability to pay dividends and make other
distributions to our shareholders is restricted.

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.
Through various hedging mechanisms, we have attempted to mitigate the impact of
changes on the results of operations of most of its projects. The basic hedging
mechanism against increased fuel and transportation costs 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 our power sales agreements, 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.

     Changes in interest rates could have a significant impact on us. Interest
rate changes 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, collars or caps on a portion of its
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 financial
instruments and other financial instruments that are sensitive to changes in
interest rates, including interest rate swaps, interest rate caps and debt
obligations.

                                       34
<PAGE>   35

     The table below 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, 1999. 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, 1999.
Future interest rates are likely to vary from those disclosed in the table.

<TABLE>
<CAPTION>
                                                 EXPECTED MATURITY DATE
                           ------------------------------------------------------------------
                            2000       2001       2002       2003        2004      THEREAFTER      TOTAL
                           -------    -------    -------    -------    --------    ----------    ----------
                                              (IN THOUSANDS)
<S>                        <C>        <C>        <C>        <C>        <C>         <C>           <C>
Long-term Debt
  Fixed Rate.............  $ 6,386    $28,662    $30,227    $32,471    $ 54,934     $981,462     $1,134,142
    Weighted average
      interest rate......     7.50%      7.49%      7.51%      7.47%       7.47%        8.01%
  Variable Rate..........  $83,728    $77,247    $48,321    $22,317    $ 23,272     $151,315        406,200
                                                                                                 ----------
    Weighted average
      interest rate......     7.08%      7.07%      7.20%      7.63%       7.45%        7.48%    $1,540,342
                                                                                                 ==========
</TABLE>

     The following tables contain information 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
notional amounts of debt covered by these agreements as of December 31, 1999 was
approximately $263,279,000. These agreements effectively changed the interest
rate, including applicable margins, on the portion of debt covered by the
notional amounts from a weighted average variable rate of 7.22% to a weighted
average effective rate of 7.09% at December 31, 1999.

            FIXED RATE PAY/VARIABLE RATE RECEIVE INTEREST RATE SWAPS

<TABLE>
<CAPTION>
  HEDGED                              FIXED     VARIABLE       FAIR
 NOTIONAL     EFFECTIVE   MATURITY    RATE        RATE        MARKET
  AMOUNT        DATE        DATE       PAY     RECEIVE(1)     VALUE
-----------   ---------   --------   -------   ----------   ----------
<S>           <C>         <C>        <C>       <C>          <C>
$51,000,000..  2/12/98    12/31/02   5.6875%      6.15%     $  711,875
  4,500,000..  8/30/90     8/30/00    9.503%     6.005%       (151,731)
 20,000,000..  7/31/00     7/31/02    6.995%         --        (31,272)
 58,163,000.. 12/20/95     7/31/06    6.078%     6.022%      1,985,472
 23,748,281.. 11/15/98     3/07/01    5.585%      6.15%        111,333
 26,304,000..  1/14/98     6/30/02    5.555%      6.21%        338,715
                                                            ----------
                                                            $2,964,392
                                                            ==========
</TABLE>

                               INTEREST RATE CAPS

<TABLE>
<CAPTION>
  HEDGED                             MAXIMUM     ACTUAL      FAIR
 NOTIONAL     EFFECTIVE   MATURITY   INTEREST   INTEREST    MARKET
  AMOUNT        DATE        DATE       RATE     RATE(1)      VALUE
-----------   ---------   --------   --------   --------   ---------
<S>           <C>         <C>        <C>        <C>        <C>
$6,824,000..  12/31/96    3/31/01     7.50%     6.2113%    $   1,312
26,304,000..   2/20/97    6/28/02     6.50%     6.2113%      119,137
80,000,000..   9/18/99    7/31/02     9.00%      6.022%           41
31,000,000..   7/31/00    7/31/02     9.00%          --       50,773
                                                           ---------
                                                           $ 171,263
                                                           =========
</TABLE>

---------------

(1) The "variable rate receive" and "actual interest rate" are based on the
    interest rates in effect as of December 31, 1999. Interest rates in the
    future are likely to vary from those disclosed in the tables above.

CHANGE OF CORPORATE FISCAL YEAR

     Effective January 1, 1998, we changed our fiscal year to commence on
January 1 and conclude on December 31 of each year. Our fiscal year previously
commenced each July 1, concluding on June 30 of the

                                       35
<PAGE>   36

following calendar year. We have restated our consolidated financial statements
for the 1997 fiscal year to a calendar basis.

YEAR 2000 COMPLIANCE

     The Year 2000 issue existed because many computer systems and applications,
including those embedded in equipment and facilities, use two digit rather than
four digit fields to designate an applicable year. As a result, those systems
and applications may not have properly recognized the year 2000 or processed
data which included such date.

     We performed extensive investigation, analysis contingency planning and
remediation to prepare our systems and applications for the Year 2000 issue. We
also communicated extensively with our critical suppliers, vendors, joint
venture partners, and major customers to assess their compliance, and our
exposure, with the Year 2000 issue.

     Our systems were Year 2000 compliant before December 31, 1999, and there
have been no significant transition issues in our computers related to the Year
2000 issue at any of our plants or our corporate headquarters. We have not
encountered any Year 2000 issues with any of our business partners, critical
suppliers, vendors, joint venture partners or major customers.

                                       36
<PAGE>   37

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                                     INDEX

<TABLE>
<CAPTION>
                                                              PAGE
                                                              ----
<S>                                                           <C>
Report of Independent Public Accountants....................   38
Consolidated Financial Statements:
     Consolidated Balance Sheets at December 31, 1999 and
      1998..................................................   39
     Consolidated Statements of Operations For the Years
      Ended December 31, 1999, 1998 and 1997................   40
     Consolidated Statements of Changes in Shareholders'
      Equity For the Years Ended December 31, 1999, 1998 and
      1997..................................................   41
     Consolidated Statements of Cash Flows For the Years
      Ended December 31, 1999, 1998 and 1997................   42
Notes to Consolidated Financial Statements..................   43
Financial Statement Schedules:
Schedule I -- Condensed Financial Information of the
  Registrant................................................   63
</TABLE>

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.
                                       37
<PAGE>   38

                    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, 1999 and 1998, and the related consolidated statements of
operations, changes in shareholders' equity and cash flows for each of the three
years in the period ended December 31, 1999. 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, 1999 and 1998 and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1999, in conformity with accounting principles generally accepted
in the United States.

     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 part of the basic financial
statements. This schedule has been subjected to the auditing procedures applied
in the audit 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,
March 9, 2000.

                                       38
<PAGE>   39

                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
                          CONSOLIDATED BALANCE SHEETS
                           DECEMBER 31, 1999 AND 1998
                             (DOLLARS IN THOUSANDS)

<TABLE>
<CAPTION>
                                                                 1999         1998
                                                              ----------   ----------
<S>                                                           <C>          <C>
                                       ASSETS
CURRENT ASSETS:
  Cash and cash equivalents.................................  $   80,344   $   48,207
  Restricted cash...........................................      81,647       40,604
  Accounts receivable.......................................      59,360       66,586
  Inventories...............................................      20,137       18,697
  Other current assets......................................       2,252        4,061
                                                              ----------   ----------
          Total current assets..............................     243,740      178,155
NET INVESTMENT IN LEASES....................................     500,195      498,614
PROPERTY, PLANT AND EQUIPMENT, net of accumulated
  depreciation of $262,963 and $225,928, respectively.......     437,483      473,065
LAND AND IMPROVEMENTS.......................................       5,764        3,981
CONSTRUCTION IN PROGRESS....................................     350,243          161
DEFERRED FINANCING COSTS, net of accumulated amortization of
  $23,950 and $15,557, respectively.........................      51,315       37,007
NATURAL GAS RESERVES........................................         744        1,557
INVESTMENTS IN AFFILIATES...................................     325,504      251,312
PROJECT DEVELOPMENT COSTS...................................       7,124           --
OTHER ASSETS................................................      76,274       55,999
                                                              ----------   ----------
                                                              $1,998,386   $1,499,851
                                                              ==========   ==========
                        LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
  Current portion of long-term debt.........................  $   90,114   $   86,255
  Accounts payable..........................................      37,588       25,511
  Accrued compensation......................................       8,415        8,096
  Accrued interest payable..................................      25,708        7,729
  Accrued dividends payable.................................       8,683        7,398
  Other accrued liabilities.................................      15,621       13,492
                                                              ----------   ----------
          Total current liabilities.........................     186,129      148,481
LONG-TERM DEBT..............................................   1,518,773    1,127,184
DEFERRED INCOME TAXES.......................................      72,980       52,306
MINORITY INTEREST...........................................      69,608       61,167
OTHER LONG-TERM LIABILITIES.................................      29,445       22,850
                                                              ----------   ----------
                                                               1,876,935    1,411,988
                                                              ----------   ----------
COMMITMENTS AND CONTINGENCIES (NOTES 9 AND 10)
SHAREHOLDERS' EQUITY:
  Common stock, no par value, 300,000 shares authorized;
     282,000 shares issued and outstanding..................         130          130
  Accumulated other comprehensive loss......................      (1,144)          --
  Accumulated earnings......................................     122,465       87,733
                                                              ----------   ----------
                                                                 121,451       87,863
                                                              ----------   ----------
                                                              $1,998,386   $1,499,851
                                                              ==========   ==========
</TABLE>

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

                                       39
<PAGE>   40

                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
                     CONSOLIDATED STATEMENTS OF OPERATIONS
              FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
          (DOLLARS IN THOUSANDS, EXCEPT FOR EARNINGS PER COMMON SHARE)

<TABLE>
<CAPTION>
                                                                1999       1998       1997
                                                              --------   --------   --------
<S>                                                           <C>        <C>        <C>
OPERATING REVENUE:
  Electric..................................................  $294,185   $293,083   $307,104
  Steam.....................................................    25,236     25,043     26,123
  Lease.....................................................    44,697     34,715         --
  Service...................................................    43,888     34,470         --
  Income from unconsolidated investment in power projects,
     net of premium amortization............................    25,464      6,474      1,412
  Other.....................................................    14,093     14,908     15,275
                                                              --------   --------   --------
                                                               447,563    408,693    349,914
                                                              --------   --------   --------
OPERATING EXPENSES:
  Fuel expense..............................................    81,835     78,420    118,731
  Cost of service...........................................    45,933     36,039         --
  Operations and maintenance................................    67,374     71,108     71,367
  General, administrative and development expenses..........    39,014     36,490     41,650
  Depreciation and amortization.............................    43,713     42,535     41,844
                                                              --------   --------   --------
                                                               277,869    264,592    273,592
                                                              --------   --------   --------
OPERATING INCOME............................................   169,694    144,101     76,322
OTHER INCOME (EXPENSE):
  Interest expense..........................................   (94,956)   (74,949)   (53,864)
  Investment and other income...............................    11,213      9,226      9,789
  Equity in net loss of affiliates, net.....................      (208)    (3,274)    (1,538)
                                                              --------   --------   --------
INCOME BEFORE MINORITY INTERESTS IN INCOME,
  INCOME TAXES AND EXTRAORDINARY LOSS.......................    85,743     75,104     30,709
MINORITY INTERESTS IN INCOME................................   (14,752)   (12,458)    (4,672)
                                                              --------   --------   --------
INCOME BEFORE INCOME TAXES AND EXTRAORDINARY LOSS...........    70,991     62,646     26,037
PROVISION FOR INCOME TAXES..................................   (27,576)   (24,914)    (9,754)
                                                              --------   --------   --------
INCOME BEFORE EXTRAORDINARY LOSS............................    43,415     37,732     16,283
EXTRAORDINARY LOSS ON EARLY EXTINGUISHMENT OF DEBT, NET OF
  INCOME TAX BENEFIT, AND MINORITY INTEREST.................        --       (743)    (1,502)
                                                              --------   --------   --------
NET INCOME..................................................  $ 43,415   $ 36,989   $ 14,781
                                                              ========   ========   ========
EARNINGS PER COMMON SHARE:
  Income before extraordinary loss..........................  $ 153.95   $ 133.80   $  57.74
  Extraordinary loss........................................        --      (2.63)     (5.33)
                                                              --------   --------   --------
                                                              $ 153.95   $ 131.17   $  52.41
                                                              ========   ========   ========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING..................   282,000    282,000    282,000
                                                              ========   ========   ========
</TABLE>

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

                                       40
<PAGE>   41

                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
           CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
              FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
         (DOLLARS IN THOUSANDS, EXCEPT FOR DIVIDENDS PER COMMON SHARE)

<TABLE>
<CAPTION>
                                                                                 ACCUMULATED
                                                                                    OTHER
                                         COMMON   COMPREHENSIVE   ACCUMULATED   COMPREHENSIVE
                                         STOCK       INCOME        EARNINGS     INCOME (LOSS)    TOTAL
                                         ------   -------------   -----------   -------------   --------
<S>                                      <C>      <C>             <C>           <C>             <C>
Balance, December 31, 1996.............   $130       $    --       $ 50,501        $    --      $ 50,631
Comprehensive income
  Net income...........................     --        14,781         14,781             --
  Other comprehensive income, net of
     tax:
     Unrealized holding gain during
       year............................     --            26             --             26
                                                     -------
       Comprehensive income:...........              $14,807                                      14,807
                                                     =======
Common stock dividends ($25.32 per
  common share)........................     --                       (7,140)            --        (7,140)
                                          ----                     --------        -------      --------
Balance, December 31, 1997.............    130                       58,142             26        58,298
Comprehensive income
  Net income...........................     --        36,989         36,989             --
  Other comprehensive income, net of
     tax:
     Realized gains included in net
       income..........................     --           (26)            --            (26)
                                                     -------
       Comprehensive income:...........              $36,963                                      36,963
                                                     =======
Common stock dividends ($26.23 per
  common share)........................     --                       (7,398)            --        (7,398)
                                          ----                     --------        -------      --------
Balance, December 31, 1998.............    130                       87,733             --        87,863
Comprehensive income
  Net income...........................     --        43,415         43,415             --
  Other comprehensive loss, net of tax:
     Unrealized holding losses during
       year............................               (1,144)                       (1,144)
                                                     -------
       Comprehensive income:...........              $42,271                                      42,271
                                                     =======
Common stock dividends ($30.79 per
  common share)........................     --                       (8,683)            --        (8,683)
                                          ----                     --------        -------      --------
Balance, December 31, 1999.............   $130                     $122,465        $(1,144)     $121,451
                                          ====                     ========        =======      ========
</TABLE>

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

                                       41
<PAGE>   42

                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
                     CONSOLIDATED STATEMENTS OF CASH FLOWS
              FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
                             (DOLLARS IN THOUSANDS)

<TABLE>
<CAPTION>
                                                                1999        1998        1997
                                                              ---------   ---------   ---------
<S>                                                           <C>         <C>         <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
     Net income.............................................  $  43,415   $  36,989   $  14,781
     Adjustments to reconcile net income to net cash
       provided by operating activities:
       Depreciation and amortization........................     43,713      42,535      41,844
       Deferred income taxes................................     23,933      14,182       4,927
       Extraordinary loss on early extinguishment of debt...         --       2,172       2,458
       Minority interest in income of joint venture, net of
          dividends.........................................      8,461     (14,494)      1,935
       Gain on sale of investment in affiliate..............         --      (2,063)         --
       Equity in net (income) loss of unconsolidated
          affiliates........................................    (22,998)     (3,200)        126
       Dividends received from unconsolidated affiliates....     26,647      13,362      15,354
       Minimum lease payments received......................     43,116      31,500          --
       Amortization of unearned lease income................    (44,697)    (33,473)         --
       Decrease (increase) in accounts receivable...........      7,487      (7,278)      3,437
       Decrease (increase) in inventories...................       (627)     (1,029)      4,385
       Decrease in accounts payable.........................     (9,791)     (4,212)     (9,490)
       Increase in accrued liabilities......................      5,074       5,179         499
       Decrease (increase) in other, net....................    (14,732)     (5,425)      2,320
                                                              ---------   ---------   ---------
     Net cash flows provided by operating activities........    109,001      74,745      82,576
                                                              ---------   ---------   ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
       Property, plant and equipment additions..............     (4,305)     (7,391)     (2,449)
       Decrease in marketable securities....................         --      42,118      21,577
       Investments in unconsolidated affiliates.............    (76,827)   (180,292)    (61,063)
       Acquisition of facilities, net of cash acquired......         --    (155,324)         --
       Construction in progress and project development
          costs.............................................    (60,697)         --          --
       Decrease in restricted cash..........................     12,243      22,952       1,532
                                                              ---------   ---------   ---------
     Net cash flows used in investing activities............   (129,586)   (277,937)    (40,403)
                                                              ---------   ---------   ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
       Proceeds from notes payable and long-term debt.......    191,340     384,104      65,171
       Repayments of notes payable and long-term debt.......   (122,255)   (193,812)   (118,778)
       Increase in deferred financing costs.................     (8,965)     (8,586)       (921)
       Common stock dividends paid..........................     (7,398)     (2,140)     (5,000)
                                                              ---------   ---------   ---------
     Net cash flows provided by (used in) financing
       activities...........................................     52,722     179,566     (59,528)
                                                              ---------   ---------   ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........     32,137     (23,626)    (17,355)
CASH AND CASH EQUIVALENTS, beginning of year................     48,207      71,833      89,188
                                                              ---------   ---------   ---------
CASH AND CASH EQUIVALENTS, end of year......................  $  80,344   $  48,207   $  71,833
                                                              =========   =========   =========
</TABLE>

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

                                       42
<PAGE>   43

                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. NATURE OF BUSINESS

     Cogentrix Energy, Inc. and subsidiary companies (collectively, the
"Company") is 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, 1999, the
Company owned or had interests in 25 Facilities in operation in the United
States with an aggregate installed capacity of approximately 4,000 megawatts.
After taking into account the part interests in the 16 plants that are not
wholly-owned by the Company, which range from 1.7% to approximately 74%, the
Company's net equity interest in the total production capability of the 25
Facilities, in operation, is approximately 1,840 megawatts. Electricity
generated by each Facility is sold to an electric utility (the "Utility") and
steam is sold to an industrial company (the "Steam Purchaser"), all under
long-term contractual agreements.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     Principles of Consolidation and Basis of Presentation -- The accompanying
consolidated financial statements include the accounts of Cogentrix Energy, Inc.
and its subsidiary companies. Wholly-owned and majority owned subsidiaries,
including a 50% owned joint venture in which the Company has effective control
through majority representation on the board of directors of the managing
general partner, are consolidated. Less-than-majority-owned subsidiaries, and
subsidiaries for which control is deemed to be temporary, 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,
Inc., 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 inventories represent the cost of natural gas 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, 1999 and 1998,
fuel and spare parts inventories are comprised of the following (dollars in
thousands):

<TABLE>
<CAPTION>
                                                                   DECEMBER 31,
                                                              ----------------------
                                                               1999           1998
                                                              -------        -------
<S>                                                           <C>            <C>
Coal........................................................  $ 8,469        $ 8,028
Natural gas.................................................    2,875          2,773
Spare parts.................................................    8,138          7,377
Fuel oil....................................................      655            519
                                                              -------        -------
                                                              $20,137        $18,697
                                                              =======        =======
</TABLE>

     Coal inventories at certain Facilities are recorded at last-in, first-out
("LIFO") cost, with the remaining Facilities' coal inventories recorded at
first-in, first-out ("FIFO") cost. The cost of coal inventories recorded on a
LIFO basis was approximately $374,000 and $305,000 less than the cost of these
inventories on a FIFO basis as of December 31, 1999 and 1998, respectively.
Spare parts inventories are recorded at average cost.

     Property, Plant and Equipment -- Property, plant and equipment is recorded
at actual cost. Substantially all property, plant and equipment consists of
cogeneration facilities which are depreciated on a straight-line

                                       43
<PAGE>   44
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

basis over their estimated useful lives (ranging from 9 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
10 years). Maintenance and repairs are charged to expense as incurred. Emergency
and rotatable spare parts inventories are included in plant and are depreciated
over the useful life of the related components.

     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 development and construction
period. For the year ended December 31, 1999, the Company capitalized $1,812,000
of interest in connection with the development and construction of power plants.
There was no interest capitalized in 1998 or 1997.

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

     Natural Gas Reserves -- Natural gas reserves consist of the cost of natural
gas purchased as long-term fuel reserves for a Facility. These reserves are
recorded at cost.

     Investments in Affiliates -- Investments in affiliates include investments
in unconsolidated entities which own or derive revenues from power projects
currently in operation and investments in unconsolidated development joint
venture entities. The Company's share of income or loss from investments in
operating power projects is included in operating revenues in the accompanying
consolidated statements of operations. The Company's share of income or loss
from investments in development joint venture entities and investments
previously held in entities which own and operate greenhouses, is included in
other income (expense) in the accompanying consolidated statements of
operations.

     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.

     Revenue Recognition -- Revenues from the sale of electricity and steam are
recorded based upon output delivered and capacity provided at rates specified
under contract terms. Significant portions of the Company's revenues have been
derived from certain electric utility customers. Two customers accounted for 47%
and 17% of revenues in the year ended December 31, 1999, 50% and 19% of revenues
in the year ended December 31, 1998 and 64% and 22% of revenues in the year
ended December 31, 1997.

     Interest Rate Protection Agreements -- The Company enters into interest
rate protection agreements with major financial institutions to fix or limit the
volatility of interest rates on its long-term debt. The differential paid or
received is recognized as an adjustment to interest expense. Any premiums
associated with interest rate protection agreements are capitalized and
amortized to interest expense over the effective term of the agreement.
Unamortized premiums are included in other assets in the accompanying
consolidated balance sheets.

     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.

                                       44
<PAGE>   45
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     Use of Estimates -- The preparation of financial statements in conformity
with generally accepted accounting principles 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.

     Comprehensive Income -- The Company adopted Statement of Financial
Accounting Standards No. 130, "Reporting Comprehensive Income," ("SFAS No.
130"), which requires companies to report all changes in equity during a period,
except those resulting from investment by owners and distribution to owners, in
a financial statement for the period in which they are recognized. The Company
has chosen to disclose Comprehensive Income, which encompasses net income and
unrealized holding losses during the year in the Consolidated Statement of
Shareholders' Equity. Prior years have been restated to conform to the SFAS No.
130 requirements.

     New Accounting Pronouncements -- In April 1998, the American Institute of
Certified Public Accounts ("AICPA") issued Statement of Position ("SOP") No.
98-5, "Reporting on the Costs of Start-Up Activities" which is effective for
financial statements for fiscal years beginning after December 15, 1998. SOP No.
98-5 requires costs incurred for start-up activities to be expensed as incurred.
For purposes of this SOP, start-up activities are defined broadly as those
one-time activities related to opening a new facility, conducting business in a
new territory, conducting business with a new class of customer or beneficiary,
initiating a new process in an existing facility, or commencing a new operation.
Start-up activities include activities related to organizing a new entity
(commonly referred to as organization costs). The Company adopted SOP No. 98-5
as of January 1, 1999. The adoption of SOP No. 98-5 did not have a material
impact on the consolidated financial statements.

     In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS
No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS
No. 133 establishes accounting and reporting standards requiring that every
derivative instrument (including certain derivative instruments embedded in
other contracts) be recorded in the balance sheets as either an asset or
liability measured at its fair value. SFAS No. 133 requires that changes in the
derivative's fair value be recognized in current earnings unless specified hedge
accounting criteria are met. Special accounting for qualifying hedges allows a
derivative's gains and losses to offset related results on the hedged item in
the income statement, and requires that a company formally document, designate,
and assess the effectiveness of transactions that receive hedge accounting.

     In June 1999, the FASB issued SFAS No. 137, "Accounting for Derivative
Investments and Hedging Activities - Deferral of the Effective Date of FASB
Statement No. 133." SFAS No. 137 requires the adoption of SFAS No. 133 to be
effective for fiscal years beginning after June 15, 2000. Early adoption is
allowed.

     The Company has not yet quantified the impacts of adopting SFAS No. 133 on
the consolidated financial statements and has not determined the timing or
method of adoption of SFAS No. 133. However, SFAS No. 133 could increase
volatility in earnings.

     Change of Fiscal Year -- Effective January 1, 1998, the Company changed its
fiscal year to commence on January 1 and conclude on December 31 of each year.
The Company's fiscal year previously commenced each July 1, concluding on June
30 of the following calendar year. The Company has restated its consolidated
financial statements for the 1997 fiscal year to a calendar year basis.

     Reclassifications -- Certain amounts included in the accompanying
consolidated financial statements for the fiscal year ended December 31, 1998
have been reclassified from their original presentation to conform with the
presentation for the year ended December 31, 1999.

                                       45
<PAGE>   46
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

3. ACQUISITIONS

     LS Power Acquisition -- In March 1998, the Company acquired from LS Power
Corporation (the "LS Power Acquisition") an approximate 74% ownership interest
in two partnerships which own and operate electric generating facilities located
in Whitewater, Wisconsin (the "Whitewater Facility") and Cottage Grove,
Minnesota (the "Cottage Grove Facility"). Each of the Cottage Grove and
Whitewater Facilities is a 245-megawatt gas-fired, combined-cycle cogeneration
facility. Commercial operations of both of these facilities commenced in the
last half of calendar 1997. The Cottage Grove Facility sells capacity and energy
to Northern States Power Company under a 30-year power sales contract
terminating in 2027. The Whitewater Facility sells capacity and energy to
Wisconsin Electric Power Company under a 25-year power sales contract
terminating in 2022. Each of the power sales contracts has characteristics
similar to a lease in that the agreement gives the purchasing utility the right
to use specific property, plant and equipment. As such, each of the power sales
contracts is accounted for as a "sales-type" capital lease in accordance with
Statement of Financial Accounting Standards ("SFAS") No. 13, "Accounting for
Leases." (see Note 7).

     The aggregate acquisition price for the equity interests in the Cottage
Grove and Whitewater Facilities acquired by the Company was approximately $158.0
million. In addition, the Company pre-funded a $16.7 million distribution to the
previous owners, which represented unused construction contingency funds and
cash flows that were accumulated by the Cottage Grove and Whitewater Facilities
prior to January 1, 1998. Cogentrix Energy, Inc. received $15.7 million of this
distribution in April 1998 and received the remaining $1 million in 1999. The
purchase price was ultimately funded with a portion of the net proceeds of the
Company's 2008 senior notes (see Note 6) and corporate cash balances.

     The Company accounted for the LS Power Acquisition using the purchase
method of accounting. The purchase price has been allocated to the assets and
liabilities acquired based on their fair market values at the date of
consummation. 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
Partnerships' 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 acquired using the effective interest method. The historical book
values of the remaining assets and liabilities approximated their fair values at
the date of consummation. The excess of the purchase price over the fair value
of the net assets acquired was approximately $27.7 million. This excess is
included in other assets on the accompanying balance sheets as of December 31,
1999 and 1998, and is being amortized on a straight line basis over the lives of
the power purchase agreements for the two facilities. The minority owner's share
of each partnership's net assets is included in minority interests on the
accompanying consolidated balance sheets as of December 31, 1999 and 1998. The
accompanying consolidated statement of operations for the year ended December
31, 1998 includes the results of operations of the acquired facilities for the
period beginning March 20, 1998 (closing date of LS Power Acquisition) to
December 31, 1998.

     During 1999, the Company and the contractor, with the concurrence of the
independent engineer, reached a final agreement regarding the settlement of all
outstanding issues and obligations of the Cottage Grove and Whitewater
facilities and the contractor pursuant to the construction contracts. The final
settlement of the construction contract provided for a payment to the contractor
of approximately $4,030,000 from funds available in Cottage Grove's and
Whitewater's construction retainage accounts. The contractor has also agreed to
extend various warranty periods and perform various repairs and inspections.
Cottage Grove and Whitewater, in turn, acknowledged that final acceptance shall
have been deemed to have occurred. Upon the release of the remaining
construction retainage accounts and settlement of outstanding warranty claims,
the Company recorded a gain of approximately $6,257,000 before minority
interests in income. The gain is included in other income in the accompanying
consolidated statements of operations for the year ended December 31, 1999.

     Batesville Acquisition -- In August 1998, the Company acquired an
approximate 52% interest in an 800-megawatt, gas-fired electric generating
facility (the "Batesville Facility") under construction in Batesville,
                                       46
<PAGE>   47
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Mississippi (the "Batesville Acquisition"). The Company has committed to provide
an equity contribution to the project subsidiary of approximately $54 million
upon the earliest to occur of (i) the incurrence of construction costs after all
project financing has been expended, (ii) an event of default under the project
subsidiary's financing arrangements or (iii) June 30, 2001. This equity
commitment is supported by a $54 million letter of credit provided under the
Company's corporate credit facility. The Company expects the Batesville
Facility, which will be operated by the Company, to commence commercial
operation in summer 2000. Electricity generated by the Batesville Facility will
be sold under long-term power purchase agreements with two investment-grade
utilities.

     The Batesville acquisition was originally accounted for under the equity
method of accounting, as the Company originally deemed its approximate 52%
interest to be temporary. As of December 31, 1999, the Company has reassessed
its ownership, and has determined that it will maintain an approximate 51%
interest in the project. As such, the Company has consolidated the net assets of
the Batesville Facility in the accompanying consolidated balance sheets at
December 31, 1999. The accompanying consolidated statements of operations at
December 31, 1999 and 1998 recognized earnings from the Batesville facility
under the equity method of accounting.

     Bechtel Asset Acquisition -- In October 1998, the Company acquired from
Bechtel Generating Company, Inc. ("BGCI") ownership interests in 12 electric
generating facilities, comprising a net equity interest of approximately 365
megawatts, and one interstate natural gas pipeline in the United States (the
"BGCI Acquisition"). The aggregate acquisition price, including acquisition
costs, for the interests in the BGCI assets was approximately $189.7 million.
The Company utilized a portion of the net proceeds from the issuance of $255
million of senior notes due 2008 to fund the BGCI Acquisition.

     The BGCI Acquisition has been accounted for using the purchase method of
accounting, which resulted in the recognition of a net purchase premium of
approximately $66.5 million. The purchase premiums or discounts related to the
BGCI Acquisition are being amortized over the remaining lives of the facilities
or over the remaining terms of the power purchase agreements. The Company uses
the equity method of accounting to account for its ownership interests in eight
of these facilities and uses the cost method of accounting for its ownership
interests in the other four facilities (see Note 4).

     Subsequent to December 31, 1999, the Company purchased an additional 1%
interest in the Logan and Northampton facilities, two of the twelve electric
generating facilities included in the BGCI Acquisition. The Company paid
approximately $1,650,000 for these additional interests. The Company will
continue to account for its 50% interest in the Logan and Northampton facilities
using the equity method.

     Indiantown Acquisition -- In June, 1999, the Company entered into an
agreement to purchase an additional 40% ownership interest in the Indiantown
cogeneration facility (the "Indiantown Acquisition"), one of the twelve electric
generating facilities included in the BGCI Acquisition, in a three-phase
transaction. The Company paid $39.8 million to acquire a 19.9% interest in the
facility in June, 1999, $36.6 million to acquire a 20% interest in the facility
in September, 1999 and $0.2 million to acquire a 0.1% interest in the facility
in November, 1999. The Company funded the purchase of these interests with
proceeds from credit facilities. These purchases resulted in a premium of
approximately $38,000,000. This premium will be amortized over the remaining
term of the power purchase agreement. The Company currently has a 50% interest
in the Indiantown facility. This investment is accounted for using the equity
method of accounting.

                                       47
<PAGE>   48
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     The following unaudited pro forma consolidated results for the Company for
the years ended December 31, 1999 and 1998 give effect to the LS Power
Acquisition, the BGCI Acquisition and the Indiantown Acquisition as if these
transactions had occurred on January 1, 1999 and January 1, 1998, respectively
(dollars in thousands, except per share amount).

<TABLE>
<CAPTION>
                                                                       PRO FORMA
                                                                YEAR ENDED DECEMBER 31,
                                                                ------------------------
                                                                   1999          1998
                                                                ----------    ----------
<S>                                                             <C>           <C>
Revenues....................................................     $452,891      $453,566
Net Income..................................................     $ 43,942      $ 37,336
Earnings per Share..........................................     $ 155.82      $ 132.41
</TABLE>

4. INVESTMENTS IN UNCONSOLIDATED POWER PROJECTS

  Birchwood Power Partners, L.P.

     The Company owns a 50% interest in Birchwood Power Partners, L.P.
("Birchwood Power"), a partnership which owns a 220-megawatt, coal fired
cogeneration facility (the "Birchwood Facility") which sells electricity to a
utility and provides thermal energy to a 36-acre greenhouse under long-term
contracts. The Birchwood Facility is operated by an affiliate of The Southern
Company under a long-term operations and maintenance agreement. The Company has
50% representation on Birchwood Power's management committee, which must approve
all material transactions of Birchwood Power. The Company is accounting for its
investment in Birchwood Power under the equity method. The Company's share of
net income of Birchwood Power is recorded net of the amortization of the $36.4
million premium paid to purchase the Company's 50% share interest in Birchwood
Power. This premium is being amortized on a straight-line basis over the
estimated useful life of the Birchwood Facility. The Company recognized
approximately $3,509,000, $3,714,000 and $1,412,000 in income from
unconsolidated investments in power projects, net of premium amortization, in
the accompanying consolidated statements of operations for the years ended
December 31, 1999, 1998 and 1997, respectively, related to its investment in
Birchwood Power. The following table presents summarized financial information
for Birchwood Power as of December 31, 1999 and 1998 and for the years ended
December 31, 1999, 1998 and 1997 (dollars in thousands):

<TABLE>
<CAPTION>
                                                           1999       1998
                                                         --------   --------
<S>                                                      <C>        <C>        <C>
BALANCE SHEET DATA:
  Current assets.......................................  $ 48,805   $ 48,416
  Noncurrent assets....................................   333,318    344,374
                                                         --------   --------
          Total assets.................................  $382,123   $392,790
                                                         ========   ========
  Current liabilities..................................  $  9,882   $  7,952
  Noncurrent liabilities...............................   323,598    329,428
  Partners' capital....................................    48,643     55,410
                                                         --------   --------
                                                         $382,123   $392,790
                                                         ========   ========
</TABLE>

<TABLE>
<CAPTION>
                                                           1999       1998       1997
                                                         --------   --------   --------
<S>                                                      <C>        <C>        <C>
INCOME STATEMENT DATA:
  Operating revenues...................................  $ 75,582   $ 71,908   $ 69,275
  Operating income.....................................    36,399     36,863     35,087
  Net income...........................................     9,740      9,747      6,451
</TABLE>

                                       48
<PAGE>   49
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

  BGCI Assets

     The Company acquired interests in 12 electric generating facilities from
BGCI on October 20, 1998 (the "BGCI assets") (see Note 3). The following table
presents the Company's ownership interests at December 31, 1999 in the BGCI
assets that are accounted for under the equity method:

<TABLE>
<CAPTION>
                                                                    PERCENT          NET
                                                                   OWNERSHIP   EQUITY INTEREST
                                                         PLANT     INTEREST       IN PLANT
                       PROJECT                         MEGAWATTS   ACQUIRED       MEGAWATTS
                       -------                         ---------   ---------   ---------------
<S>                                                    <C>         <C>         <C>
Logan................................................     218       49.0%           106.8
Northampton..........................................     110        49.0            53.9
Indiantown...........................................     380        50.0           190.0
Carney's Point.......................................     262        10.0            26.2
Panther Creek........................................      83        12.2            10.1
Scrubgrass...........................................      85        20.0            17.0
Gilberton............................................      82        19.6            16.1
Morgantown...........................................      62        15.0             9.3
</TABLE>

     The Company recognized approximately $21,954,000 and $2,760,000 in income
from unconsolidated investments in power projects in the accompanying
consolidated statement of operations for the year ended December 31, 1999 and
for the period from October 20, 1998 to December 31, 1998 related to its
investment in the projects acquired from BGCI. The following table presents
summarized combined financial data of the unconsolidated power projects acquired
from BGCI being accounted for under the equity method as of December 31, 1999
and 1998 and for the year ended December 31, 1999 and for the period from
October 20, 1998 to December 31, 1998 (dollars in thousands):

<TABLE>
<CAPTION>
                                                                   DECEMBER 31,
                                                              -----------------------
                                                                 1999         1998
                                                              ----------   ----------
<S>                                                           <C>          <C>
BALANCE SHEET DATA:
  Current assets............................................  $  157,396   $  131,178
  Noncurrent assets.........................................   2,988,277    2,827,875
                                                              ----------   ----------
          Total assets......................................  $3,145,673   $2,959,053
                                                              ==========   ==========
  Current liabilities.......................................  $  205,667   $  137,205
  Noncurrent liabilities....................................   2,523,826    2,398,944
  Partners capital..........................................     416,180      422,904
                                                              ----------   ----------
                                                              $3,145,673   $2,959,053
                                                              ==========   ==========
</TABLE>

<TABLE>
<CAPTION>
                                                                             FOR THE PERIOD
                                                      FOR THE YEAR ENDED   OCTOBER 20, 1998 TO
                                                      DECEMBER 31, 1999     DECEMBER 31, 1998
                                                      ------------------   -------------------
<S>                                                   <C>                  <C>
INCOME STATEMENT DATA:
  Operating revenues................................       $624,010              $96,622
  Operating income..................................        365,429               51,948
  Net income........................................         56,818               15,071
</TABLE>

5. INVESTMENT IN OTHER UNCONSOLIDATED AFFILIATES

     The Company makes investments in other joint venture partnerships whose
purpose is to develop power projects. The Company utilizes the equity method of
accounting for those partnerships in which it holds an ownership interest
between 20% and 50%. The Company recognized approximately $208,000, $307,000,
and $471,000 in equity losses for the years ended December 31, 1999, 1998 and
1997, respectively, related to its

                                       49
<PAGE>   50
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

investments in these partnerships. These losses are reflected in equity in loss
of affiliates in the accompanying consolidated statements of operations.

     The Company entered into an agreement with Agro Power Development, Inc. a
developer and operator of greenhouse facilities, ("Agro") to make investments in
partnerships which develop, construct and operate greenhouses which produce
tomatoes. The Company obtained a 50% interest in four limited partnerships which
had a combined 107 acres of production capacity in operation. In December 1998,
the Company entered into an agreement to sell its 50% interest in the
partnerships to EcoScience Corporation ("EcoScience"), the parent of Agro. In
return for its 50% interest, the Company received 1,000,000 shares of common
stock of EcoScience and a note receivable from EcoScience (the "EcoScience
Note") in the amount of approximately $20.6 million. The original note
receivable from EcoScience accrued interest at 11.25% per annum with principal
and interest due on March 15, 1999, (see below), and was secured by a pledge of
all of the outstanding stock of Agro. The Company recognized a gain of $2.1
million related to the fair market value of common stock received from the sale
of the greenhouse partnerships. This gain is included in investment and other
income in the accompanying consolidated statement of operations for the year
ended December 31, 1998. As of December 31, 1999, the Company has recorded an
unrealized holding loss on the EcoScience common stock, which has been included
in accompanying consolidated financial statements.

     On March 15, 1999, the Company agreed to extend the due date for principal
and interest on the EcoScience Note to June 30, 1999. In exchange for this
extension, the Company received an extension fee of $1 million in the form of a
promissory note from EcoScience, which bears the same terms as the original
note. As of December 31, 1999 and 1998, the Company had a recorded investment in
the EcoScience Note of $21,600,000 and $20,600,000, respectively. The Company
has an allowance for credit losses related to the entire balance of its recorded
investment in the EcoScience Note of approximately $14,400,000 and $11,800,000
at December 31, 1999 and 1998, respectively. Currently, the Company is recording
interest income only as cash is received. The Company recognized and received no
interest on this note for the year ended December 31, 1999. The Company would
have recognized gross interest income of approximately $2,400,000 for the year
ended December 31, 1999 if EcoScience would have been current in their interest
payments.

     Subsequent to December 31, 1999, the Company entered into an agreement to
exchange the EcoScience Note and all outstanding interest due for a promissory
note in the amount of $15,900,000. The promissory note bears interest at 5% per
year, and is due in five annual installments of $3,180,000, beginning on
December 1, 2003 until December 1, 2007. In consideration for this exchange,
EcoScience authorized and issued 333,333 shares of Series A Preferred Stock of
EcoScience to the Company.

     Prior to the sale of the greenhouse partnerships, the Company accounted for
its investment in these partnerships under the equity method, and recognized
approximately $2,967,000, and $1,066,000 in equity losses in the accompanying
consolidated statements of operations for the years ended December 31, 1998 and
1997, respectively.

                                       50
<PAGE>   51
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

6. LONG-TERM DEBT

     The following long-term debt was outstanding as of December 31, 1999 and
1998, respectively (dollars in thousands):

<TABLE>
<CAPTION>
                                                                   DECEMBER 31,
                                                              -----------------------
                                                                 1999         1998
                                                              ----------   ----------
<S>                                                           <C>          <C>
PROJECT FINANCING DEBT:
HOPEWELL FACILITY:
     Note payable to banks..................................  $   51,000   $   67,000
PORTSMOUTH FACILITY:
     Note payable to banks..................................      41,649       43,129
ROCKY MOUNT FACILITY:
     Note payable to financial institution..................     120,182      123,422
RINGGOLD FACILITY:
     Note payable to banks..................................      10,995       13,440
RICHMOND FACILITY:
     Commercial paper notes payable, net of unamortized
       issue discount of $745 and $350, respectively, and
       tax-exempt bonds.....................................     171,848      185,814
ELIZABETHTOWN, LUMBERTON AND KENANSVILLE FACILITIES:
     Notes payable to banks.................................       6,824       16,964
ROXBORO AND SOUTHPORT FACILITIES:
     Note payable to banks..................................      52,608       73,400
COTTAGE GROVE AND WHITEWATER FACILITIES:
     Bonds payable, due 2010 and 2016, including unamortized
       fair market value adjustment related to purchase of
       facilities of $20,386 and $21,345....................     352,386      353,345
BATESVILLE FACILITY:
     Bonds payable, due 2014 and 2025.......................     326,000           --
OKLAHOMA FACILITY:
     Construction note payable to banks.....................      70,531           --
CEA CREDIT FACILITY.........................................      66,400           --
OTHER.......................................................         960        1,139
                                                              ----------   ----------
          Total Project Financing Debt......................   1,271,383      877,653
SENIOR NOTES (including net unamortized gain (loss) on hedge
  transactions of $(18,246) and $(20,048), respectively and
  net bond issuance premium of $750 and $835,
  respectively).............................................     337,504      335,786
                                                              ----------   ----------
Total Long-Term Debt........................................   1,608,887    1,213,439
Less: Current portion.......................................     (90,114)     (86,255)
                                                              ----------   ----------
Long-term portion...........................................  $1,518,773   $1,127,184
                                                              ==========   ==========
</TABLE>

     Information related to each of these borrowings is as follows:

HOPEWELL FACILITY:

     The Hopewell Facility's project debt agreement was amended in February 1998
resulting in an extension of the final maturity of the note payable by six
months to December 31, 2002. The amended terms of the loan agreement increased
outstanding borrowings by $34.6 million, the proceeds of which (net of
transaction costs) were paid as a distribution to the partners in that project.
The amended note payable accrues interest at an annual rate equal to the
applicable LIBOR rate, as chosen by the Company, plus an additional margin of

                                       51
<PAGE>   52
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

1.00% (7.15% at December 31, 1999). The amended note payable also provides for a
$5 million letter of credit to secure the project's obligation to pay debt
service. Cogentrix Energy, Inc. has indemnified the lenders of the note payable
for any cash deficits the Hopewell Facility could experience as a result of
incurring certain costs, subject to a cap of $10.6 million.

     An extraordinary loss of $2.4 million was recorded in the first quarter of
1998 related to the write-off of unamortized deferred financing costs from the
original project debt and a swap termination fee on an interest rate swap
agreement hedging the original project debt. The Company's share of this
extraordinary loss of approximately $700,000, net of a tax benefit of
approximately $500,000 and $1.2 million of minority interest, is shown in the
accompanying consolidated statements of operations.

PORTSMOUTH FACILITY:

     The Portsmouth Facility's project debt agreement was amended in December
1997, resulting in the extension of the final maturity of the loan by three
months to December 31, 2002. The amended terms of the loan agreement also
increased the outstanding credit commitment from the project lenders to $43.5
million in the form of a revolving credit facility. As of December 31, 1999, the
balance outstanding under the credit facility is approximately $41,600,000 of
which $20,400,000 was outstanding under the revolving credit facility. The
amended terms of the loan agreement provide for interest to accrue at an annual
rate equal to the applicable LIBOR rate, as chosen by the Company, plus an
additional margin of 1.0% (7.15% at December 31, 1999). The banks' outstanding
credit commitment under the loan agreement is reduced quarterly, with interest
payable the earlier of the maturity of the applicable LIBOR term or quarterly
through December 2002. The loan agreement also provides for a $6 million letter
of credit to secure the project's obligations to pay debt service. Cogentrix
Energy, Inc. has indemnified the lenders of the senior credit facility for any
cash deficits the Portsmouth Facility could experience as a result of incurring
certain costs, subject to a cap of $30 million.

     An extraordinary loss of $2,458,000 was recorded in the year ended December
31, 1997 related to the write-off of unamortized deferred financing costs from
the original senior loan of $1,395,000 and net swap termination fees of
$1,063,000 related to interest rate swap agreements hedging the original project
debt. This extraordinary loss is shown net of a tax benefit of $956,000 in the
accompanying consolidated statement of operations.

ROCKY MOUNT FACILITY:

     The note payable to financial institution consists of a $120,182,000 senior
loan which accrues interest at a fixed annual rate of 7.58%. Payment of
principal and interest is due quarterly through December 2013.

RINGGOLD FACILITY:

     The note payable to banks consists of a senior loan which accrues interest
at an annual rate equal to the applicable LIBOR rate, as chosen by the Company,
plus 1.35% per annum (7.36% at December 31, 1999). Interest is payable at the
earlier of the maturity of the applicable LIBOR term or quarterly in arrears.
Payments of principal under the senior loan are due semiannually through April
2004.

     In January 1998, the Company signed an agreement with Pennsylvania Electric
Company ("Penelec") to terminate the project subsidiary's power purchase
agreement. This termination agreement was the result of a request for proposals
from the utility to buy-back or restructure power sales agreements issued to all
major operating independent power producers in Penelec's territory in April
1997. The termination agreement with Penelec provides for a payment to the
project subsidiary of approximately $20.4 million, which will be sufficient to
retire all of the project subsidiary's outstanding debt. The buy-back of the
power purchase agreement is subject to the issuance of a satisfactory final
order by the Pennsylvania Public Utility

                                       52
<PAGE>   53
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Commission, which is not subject to appeal, granting Penelec the authority to
fully recover from its customers the consideration paid under the buyout
agreement. Management does not expect the termination of this project
subsidiary's power purchase agreement, if it occurs, to have an adverse impact
on the Company's consolidated results of operations or financial position.

RICHMOND FACILITY:

     Commercial paper notes outstanding are supported by an irrevocable,
direct-pay letter of credit provided by a syndicate of banks (the "Banks"). The
maximum amount of commercial paper notes supported by the letter of credit is
$124,600,000 as of December 31, 1999. The annual interest rate incurred is the
yield on the commercial paper notes plus a 1.25% to 1.50% per annum fee
(weighted average rate of 7.27% at December 31, 1999) paid to the Banks for
providing the letter of credit.

     Tax-exempt industrial development bonds (the "Bonds") have been issued to
support the purchase of certain pollution control and solid waste disposal
equipment for the Facility ($48 million outstanding at December 31, 1999 and
1998). Principal and interest payments on the Bonds are supported by an
irrevocable, direct-pay letter of credit provided by the Banks. The annual
interest rate is the yield on the Bonds plus a 1.25% to 1.50% per annum fee
(5.6% at December 31, 1999). The letters of credit described above are part of
one credit facility (the "Credit Facility"). The Credit Facility provides for
commitment reductions through September 2007.

ELIZABETHTOWN, LUMBERTON AND KENANSVILLE FACILITIES:

     The project debt on the Elizabethtown, Lumberton and Kenansville Facilities
consists of a senior note payable that accrues interest at an annual rate equal
to the applicable LIBOR rate, as chosen by the Company, plus 1% (7.21% at
December 31, 1999). Principal is payable quarterly with interest payable at the
earlier of the maturity of the applicable LIBOR term or quarterly through
September 2000. The senior credit facility also provides for a $3.3 million
letter of credit to secure the project's obligations to pay debt service.

ROXBORO AND SOUTHPORT FACILITIES:

     The project debt agreement for the Roxboro and Southport Facilities
consists of a senior note payable that accrues interest at an annual rate equal
to the applicable LIBOR rate, as chosen by the Company, plus 1% through
September 2001 and 1.125% thereafter (7.21% at December 31, 1999). Principal is
payable quarterly with interest payable at the earlier of the maturity of the
applicable LIBOR term or quarterly through June 2002. The senior credit facility
also provides for a $6.5 million letter of credit to secure the project's
obligations to pay debt service.

COTTAGE GROVE AND WHITEWATER FACILITIES:

     The project debt of the Cottage Grove and Whitewater Facilities consist of
the following senior secured bonds (dollars in thousands):

<TABLE>
<S>                                                           <C>
7.19% Senior Secured Bonds due June 30, 2010................  $105,551
8.08% Senior Secured Bonds due December 30, 2016............   226,449
                                                              --------
                                                              $332,000
                                                              ========
</TABLE>

     Interest and principal is payable on these bonds semi-annually on June 30
and December 30 of each year. Principal payments commence on June 30, 2000 for
the 2010 Bonds and December 30, 2010 for the 2016 Bonds.

                                       53
<PAGE>   54
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     In December 1998, Cogentrix Mid-America, Inc., a wholly-owned subsidiary,
which holds the Company's interest in the Cottage Grove and Whitewater
Facilities, entered into a credit agreement with a bank to provide for a $25
million revolving credit facility available in a form of the issuance of letters
of credit to support the debt reserve requirements for the 2010 and 2016 Bonds
which vary from $12.9 million to $28.1 million over the term of the Bonds. The
credit agreement also provides for direct advances up to the amount of any
excess of the $25 million commitment over the then debt service reserve
requirement. As of December 31, 1999, letters of credit totalling $14.1 million
were issued and outstanding under the credit agreement.

JENKS FACILITY:

     The construction loan agreement for the Jenks facility consists of a
construction note payable up to $350 million to construct an 800-megawatt
combined cycle natural gas-fired generating facility. The construction loan will
convert to a term loan, due December 2006, upon commencement of commercial
operations. The loan agreement provides for interest to accrue at an annual rate
equal to the applicable LIBOR rate, as chosen by the Company plus 1.25% to 1.50%
per annum. The loan facility also provides for an $8 million letter of credit to
secure the project's obligation to pay debt service.

     In accordance with the terms of the project financing agreements, the
Company is committed to provide an equity contribution to the project subsidiary
of approximately $56.9 million upon the earliest to occur of (a) an event of
default under the project subsidiary's financing agreement, (b) the incurrence
of construction costs after all project financing has been expended or (c) June
24, 2002. The equity contribution commitment will be reduced by approximately
$8.2 million upon the project subsidiary's receipt of a waste water discharge
permit. This equity contribution commitment is supported by a letter of credit,
which is provided under the corporate credit facility.

BATESVILLE FACILITY:

     The project debt of the Batesville Facility consists of the following
senior secured bonds (dollars in thousands):

<TABLE>
<S>                                                           <C>
7.16% Senior Secured Bonds due January 15, 2014.............  $150,000
8.16% Senior Secured Bonds due June 15, 2025................   176,000
                                                              --------
                                                              $326,000
                                                              ========
</TABLE>

     Interest and principal is due on these bonds semi-annually on January 15
and July 15 each year. Principal payments commence on July 15, 2001 for the 2014
Bonds, and July 15, 2014 for the 2025 Bonds.

CEA CREDIT FACILITY:

     In September 1999, one of the Company's wholly-owned subsidiaries,
Cogentrix Eastern America, Inc., formed to hold the Company's ownership interest
in twelve electric generating facilities acquired in the BGCI Acquisition,
entered into a $75 million, three-year credit facility. The commitment under
this facility reduces to $67.5 million after one year and to $60 million after
two years. As of December 31, 1999, advances totalling $66.4 million were
outstanding under this facility

INTEREST RATE PROTECTION AGREEMENTS:

     The Company has entered into interest rate cap and interest rate swap
agreements (Note 12) 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, 1999 and 1998 were approximately $263,279,000 and
$343,112,000, respectively. The agreements effectively change the interest rate
on the portion of debt covered by the notional

                                       54
<PAGE>   55
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

amounts from a weighted average variable rate of 7.2% at December 31, 1999 to a
weighted average effective rate of 7.1% at December 31, 1999. These agreements
expire at various dates through July 2006.

SENIOR NOTES:

     On March 15, 1994, Cogentrix Energy, Inc. 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, Inc. 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 which has been deferred and
included as part of the 2004 Notes on the accompanying consolidated balance
sheets. This deferred gain will be recognized over the term of the 2004 Notes,
reducing the effective rate of interest on the 2004 Notes to 7.5%. The 2004
Notes require annual sinking fund payments beginning in March 2001. 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, Inc. 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 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
are recognized over the term of the 2008 Notes, resulting in an overall
effective rate of approximately 9.59%.

CORPORATE CREDIT FACILITY:

     In May 1997, the Company entered into a credit agreement with Australia and
New Zealand Banking Group Limited, as agent for a group of lending banks. In
October 1998, the Company amended and restated the corporate credit facility to
provide for $125 million of revolving credit available through October 2001 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 currently 50 basis points per
annum, payable each quarter on the outstanding unused portion of the Corporate
Credit Facility. As of December 31, 1999, the Company has used this credit
facility to issue approximately $117 million of letters of credit in connection
with investments made in electric-generating plants, and two plants under
construction. Subsequent to December 31, 1999, the Corporate Credit Facility was
amended to provide for $175 million of revolving credit and to modify the
covenants. The revolving credit facility has been extended through October,
2002.

     The project financing debt is substantially non-recourse to the Company (as
parent). 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 which 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 the Company (as parent) 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

                                       55
<PAGE>   56
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 agreement. These covenants did not restrict the
Company's ability to declare dividends of $8.7 million and $7.4 million to the
Company's shareholders for the years ended December 31, 1999 and 1998.

     Future maturities of long-term debt at December 31, 1999, excluding the
unamortized issue discounts on commercial paper notes, 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
are as follows (dollars in thousands):

<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
------------
<S>                                                       <C>
2000....................................................   $   90,114
2001....................................................      105,911
2002....................................................      144,949
2003....................................................       54,789
2004....................................................       78,206
Thereafter..............................................    1,132,773
                                                           ----------
                                                           $1,606,742
                                                           ==========
</TABLE>

     Cash paid for interest on the Company's long-term debt amounted to
$92,228,000, $76,358,000, and $55,339,000 for the years ended December 31, 1999,
1998 and 1997, respectively.

7. SALES TYPE CAPITAL LEASE

     The power purchase agreements acquired by the Company as a result of the LS
Power Acquisition have characteristics similar to leases in that the agreements
confer to the purchasing utility the right to use specific property, plant and
equipment. At the commercial operations date, the partnerships accounted for the
power purchase agreements as "sales-type" capital leases in accordance with
Statement of Financial Accounting Standards (SFAS) No. 13, "Accounting for
Leases".

     The components of the net investment in the leases at December 31, 1999 and
1998 are as follows (dollars in thousands):

<TABLE>
<CAPTION>
                                                                 1999         1998
                                                              ----------   ----------
<S>                                                           <C>          <C>
Gross Investment in Leases..................................  $1,097,787   $1,140,909
Unearned Income on Leases...................................    (597,592)    (642,295)
                                                              ----------   ----------
Net Investment in Leases....................................  $  500,195   $  498,614
                                                              ==========   ==========
</TABLE>

     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.

                                       56
<PAGE>   57
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     Estimated minimum lease payments over the remaining term of the power
purchase agreements as of December 31, 1999 are as follows (dollars in
thousands):

<TABLE>
<S>                                                       <C>
2000....................................................   $   45,180
2001....................................................       45,187
2002....................................................       47,253
2003....................................................       49,052
2004....................................................       50,957
Thereafter..............................................      860,158
                                                           ----------
          Total.........................................   $1,097,787
                                                           ==========
</TABLE>

8. INCOME TAXES

     The provision (benefit) for income taxes for the years ended December 31,
1999, 1998 and 1997, consists of the following (dollars in thousands):

<TABLE>
<CAPTION>
                                                           YEARS ENDED DECEMBER 31,
                                                         ----------------------------
                                                          1999       1998       1997
                                                         -------    -------    ------
<S>                                                      <C>        <C>        <C>
Current
  Federal..............................................  $   980    $ 6,561    $3,619
  State................................................    2,663      3,698       252
                                                         -------    -------    ------
                                                           3,643     10,259     3,871
                                                         -------    -------    ------
Deferred
  Federal..............................................   22,402     13,565     3,942
  State................................................    1,531        617       985
                                                         -------    -------    ------
                                                          23,933     14,182     4,927
                                                         -------    -------    ------
                                                         $27,576    $24,441    $8,798
                                                         =======    =======    ======
Statements of Operations Captions
  Tax effect of extraordinary loss.....................  $    --    $  (473)   $ (956)
  Provision for income taxes...........................   27,576     24,914     9,754
                                                         -------    -------    ------
                                                         $27,576    $24,441    $8,798
                                                         =======    =======    ======
</TABLE>

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

<TABLE>
<CAPTION>
                                                              YEARS ENDED DECEMBER 31,
                                                              -------------------------
                                                              1999      1998      1997
                                                              -----     -----     -----
<S>                                                           <C>       <C>       <C>
Federal statutory tax rate..................................  35.0%     35.0%     35.0%
State income taxes, net of loss carryforwards and federal
  tax impact................................................   4.7       3.4       3.4
Other.......................................................  (0.9)      1.4      (1.1)
                                                              ----      ----      ----
Effective tax rate..........................................  38.8%     39.8%     37.3%
                                                              ====      ====      ====
</TABLE>

     The net current and noncurrent components of deferred income taxes
reflected in the accompanying consolidated balance sheets as of December 31,
1999 and 1998 are as follows (dollars in thousands):

<TABLE>
<CAPTION>
                                                                 DECEMBER 31,
                                                              ------------------
                                                               1999       1998
                                                              -------    -------
<S>                                                           <C>        <C>
Net current deferred tax liability (asset)..................  $   227    $(2,269)
Net noncurrent deferred tax liability.......................   72,980     52,306
                                                              -------    -------
Net deferred tax liability..................................  $73,207    $50,037
                                                              =======    =======
</TABLE>

                                       57
<PAGE>   58
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     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, 1999 and 1998 are as
follows (dollars in thousands):

<TABLE>
<CAPTION>
                                                                  DECEMBER 31,
                                                              --------------------
                                                                1999        1998
                                                              --------    --------
<S>                                                           <C>         <C>
Deferred tax liabilities:
  Depreciation/amortization and book/tax basis
     differences............................................  $ 56,436    $ 59,435
  Book/tax timing differences on joint venture interest.....    74,968      34,043
  Other.....................................................    21,663      10,124
                                                              --------    --------
                                                               153,067     103,602
                                                              --------    --------
Deferred tax assets:
  Depreciation/amortization and book/tax basis
     differences............................................    14,687      13,463
  Operating loss carryforwards..............................    20,202       3,852
  Accrued expenses not currently deductible.................     7,220       7,211
  Alternative minimum tax credit carryforwards..............    24,002      22,867
  Other.....................................................    13,749       6,172
                                                              --------    --------
                                                                79,860      53,565
                                                              --------    --------
  Net deferred tax liability................................  $ 73,207    $ 50,037
                                                              ========    ========
</TABLE>

     As of December 31, 1999, the Company has net federal operating loss
carryforwards available to offset future federal taxable income of approximately
$25,082,000 which expire in 2019. The Company also has state net operating loss
carryforwards available to offset future state taxable income of approximately
$140,431,000 which expire from 2005 to 2019. In addition, the Company has
alternative minimum tax credit carryforwards of approximately $24,002,000 which
are available to reduce future federal regular income taxes, if any, over an
indefinite period.

     Cash paid for income taxes amounted to approximately $2,142,000,
$11,367,000, and $12,127,000 for the years ended December 31, 1999, 1998 and
1997, respectively.

9. LEASE COMMITMENTS

     The Company leases an office building and land from Equipment Leasing
Partners ("ELP"), a partnership formed by several of the Company's shareholders,
with remaining initial lease terms of 3 years and 47 years, respectively. The
Company also leases certain equipment from ELP used to transport and handle coal
and ash at certain Facilities. Future minimum lease payments under the
agreements with ELP and agreements with other equipment providers at December
31, 1999 are as follows (dollars in thousands):

<TABLE>
<CAPTION>
                                                        OTHER
YEAR ENDED                                            EQUIPMENT
DECEMBER 31,                                  ELP     PROVIDERS   TOTAL
------------                                 ------   ---------   ------
<S>                                          <C>      <C>         <C>
2000.......................................  $1,575     $182      $1,757
2001.......................................   1,375       96       1,471
2002.......................................   1,348       --       1,348
2003.......................................   1,118       --       1,118
2004.......................................   1,056       --       1,056
Thereafter.................................   5,076       --       5,076
</TABLE>

                                       58
<PAGE>   59
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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
30 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:

          (i) The Company is required to sell electricity generated by each
     Facility to a Utility and the Utility is required to purchase this
     electricity or make capacity payments at pre-established or annually
     escalating prices.

          (ii) The Company is required to sell and the Steam Purchaser is
     required to purchase a minimum amount of process steam from each Facility
     for each contract year. The Steam Purchaser is generally required to
     purchase its entire steam requirements from the Company. The purchase price
     of steam under these contracts escalates annually or is fixed and
     determinable during the term of the contracts.

          (iii) The Company is obligated to purchase and fuel suppliers are
     required to supply all of the fuel requirements of each Facility. Fuel
     requirements include the quality and estimated quantity of fuel required to
     operate each Facility. The price of fuel escalates annually for the term of
     each contract. In addition, the Company has transportation contracts with
     various entities to deliver the fuel to each Facility. These contracts also
     provide for annual escalations throughout the term of the contracts.

     Effective September 1996, the Company amended the power sales agreements on
its Lumberton, Elizabethtown, Kenansville, Roxboro and Southport Facilities.
These amendments provide the purchasing utility additional rights related to the
dispatch of the Facilities and eliminated the purchase options which the utility
held related to the Roxboro and Southport Facilities.

     The Company has also amended the power sales agreement on its Portsmouth
Facility and Hopewell Facility, effective December 1997 and February 1998,
respectively. These amendments provide the purchasing utility additional rights
related to the dispatch of these Facilities. The terms of Portsmouth's amended
power sales agreement also eliminated Portsmouth's accrued obligation to return
previously disallowed capacity payments to the purchasing utility.

     Under the terms of certain contracts with electricity purchasers, the
Company is obligated to pay up to $37,350,000 in aggregate liquidated damages to
the respective electricity purchasers if the respective facility does not
demonstrate certain operating and reliability standards. Banks have issued
letters of credit, non recourse to Cogentrix Energy, Inc., in favor of the
electricity purchaser which secure the Company's obligations to the electricity
purchaser under this provision of the contracts.

     Under certain power sales agreements, the Utility 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
Utility from recovering such payments made under such power sales agreement.
However, in most cases, the Utility 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 or certain subsidiaries' cash flow. The Company incurred
expense under these plans of approximately $8,236,000, $5,758,000, and
$9,123,000 for the fiscal years ended December 31, 1999, 1998 and 1997,
respectively. During the fiscal year ended December 31, 1997, the Company
incurred $10.7 million of expenses in connection with the restructuring or
termination of these incentive compensation plans.

                                       59
<PAGE>   60
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     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 $1,664,000, $1,435,000, and $1,483,000 for the
fiscal years ended December 31, 1999, 1998 and 1997, respectively.

     The Company has a non-qualified Supplemental Retirement Plan agreement with
certain directors and officers. Under the plan, the participants may elect to
have up to 35% of their compensation deferred. In addition, the Company will
credit the participant's deferral account, up to specified limitations, with an
amount equal to the participant 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
$10,350,000 and $4,853,000 at December 31, 1999 and 1998, respectively) which is
used to fully fund the liability under the plan on an annual basis. The Company
is owner and beneficiary of the 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 Utility. In
addition, Cogentrix Energy, Inc. has indemnified the project lenders of certain
subsidiaries for any cash deficits such subsidiaries could experience as a
result of incurring certain costs, subject to an aggregate cap of $40.6 million.

     Cogentrix Delaware Holdings, Inc., a wholly-owned subsidiary of Cogentrix
Energy, Inc., has guaranteed all of the existing and future senior, unsecured
outstanding indebtedness for borrowed money of Cogentrix Energy, Inc. This
guarantee, provided for in the credit agreement for the Corporate Credit
Facility, expires by its terms in 2002, unless the term of the credit agreement
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 credit agreement.

     Turbine Deposits -- The Company has entered into commitments with a turbine
supplier to purchase a specified number of turbines with specified delivery
dates. The Company has made approximately $11,205,000 million in non-refundable
deposits related to these commitments through December 31, 1999. The Company
expects to make additional deposits of approximately $82.9 million, of which
approximately $75.8 million would be repaid or funded from proceeds of financing
the Company anticipates closing.

     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 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 and after consultations with various counsel retained to represent
the subsidiary in the defense of such claims -- 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, 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.

                                       60
<PAGE>   61
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 the Trustees were approximately $118,494,000 and $56,637,000
at December 31, 1999 and 1998, 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.

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

     The Company invests its temporary cash balances in U.S. government
obligations, corporate obligations and financial instruments of highly-rated
financial institutions. A substantial portion of the Company's accounts
receivable are 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, 1999 and 1998, 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, 1999,
and 1998. The fair value of the Company's fixed-rate borrowings at December 31,
1999 and 1998 is $30,480,000 lower and $84,194,000 greater than the historical
carrying value of $1,133,181,000 and $810,422,000, 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 (Note 6). 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. As of December 31,
1999 and 1998, the net unrealized gain (loss) on the interest rate protection
agreements was $2,325,000 and $(6,086,000), respectively.

13. RELATED PARTY TRANSACTIONS

     The Company has notes receivable and advances due from shareholders and an
affiliated entity of approximately $1,105,000 and $405,000 as of December 31,
1999 and 1998, respectively. The notes receivable bear interest at various
rates, all of which are in excess of the prime rate in effect from time to time,
and have specified repayment terms. These notes have been classified as other
assets in the accompanying consolidated balance sheets.

     The Company leases certain equipment, its principal executive office
building and land from an affiliated entity. Payments by the Company under these
lease agreements were approximately $1,887,000, $1,694,000, and $1,851,000, for
the years ended December 31, 1999, 1998 and 1997, respectively.

     A shareholder, director and former executive officer was a participant in
management incentive compensation plans (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 net cash flow, as defined, of
certain subsidiaries. Total compensation to the shareholder under the consulting
agreement and incentive compensation plans was approximately $290,000, $278,000,
and $324,000 for the years ended December 31, 1999, 1998 and 1997, respectively.

     Subsequent to December 31, 1999, 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
                                       61
<PAGE>   62
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

agreement provides for monthly payments of $29,202 through December 31, 2000,
monthly payments of $18,251 for January 2001 through December 2001, monthly
payments of $15,644 for January 2002 through December 2003 and monthly payments
of $10,429 for January 2004 through December 2004.

     Three shareholders, who were also employees of the Company, terminated
their participation in certain management incentive compensation plans during
the fiscal year ended December 31, 1997 (Note 10). The Company recognized $3.5
million of expense in the year ended December 31, 1997 related to the
termination of the shareholders' participation in these plans.

14. SUBSEQUENT EVENT

     The Company has been developing jointly with Avista Power, Inc. a 270
megawatt, combined cycle, natural gas-fired electric generating facility to be
located in Rathdrum, Idaho. The Company and Avista Power own a 51% and 49%
interest, respectively, in a partnership that will own the Rathdrum facility. On
March 9, 2000, the partnership closed a credit facility with a bank and a
financial institution which provide for a $126 million construction loan and a
$5 million debt service reserve letter of credit. In accordance with the terms
of the financing agreements, the Company has committed to provide an equity
contribution to the partnership of approximately $16.7 million upon the earliest
to occur of (a) an event of default under the project's financing agreements,
(b) the incurrence of construction costs after all project financing has been
expended, or (c) October 1, 2002. This equity contribution agreement is
supported by a letter of credit, which is provided under the corporate credit
facility. In addition, Cogentrix Energy has agreed to make additional stand-by
equity contributions to cover certain contingent costs during the construction
period capped at $3.6 million.

     An indirect, wholly-owned subsidiary of Cogentrix Energy has entered into
an engineering, procurement and construction (EPC) contract with the partnership
to construct the Rathdrum facility. Cogentrix Energy is providing a guarantee
supporting the subsidiary's obligations under the EPC contract. The Rathdrum
facility, which the Company will operate, is anticipated to begin operation in
the third quarter of 2001. Avista Turbine Power, Inc. will deliver natural gas
to the plant and purchase the electrical output of the facility under a 25 year
power purchase agreement.

                                       62
<PAGE>   63

                                                                      SCHEDULE I

                             COGENTRIX ENERGY, INC.
                     CONDENSED BALANCE SHEETS OF REGISTRANT
                           DECEMBER 31, 1999 AND 1998
                             (DOLLARS IN THOUSANDS)

<TABLE>
<CAPTION>
                                                                1999       1998
                                                              --------   --------
<S>                                                           <C>        <C>
                                     ASSETS
CURRENT ASSETS:
  Cash and cash equivalents.................................  $ 35,243   $ 14,884
  Restricted cash...........................................     7,549      7,351
  Accounts receivable.......................................       436      1,313
  Accounts receivable from affiliates, net..................    37,678     20,997
  Other current assets......................................       279        200
                                                              --------   --------
          Total current assets..............................    81,185     44,745
                                                              --------   --------
INVESTMENT IN SUBSIDIARIES (ON THE EQUITY METHOD)...........   428,423    408,780
                                                              --------   --------
EQUIPMENT, net of accumulated depreciation..................     2,257      2,661
                                                              --------   --------
OTHER ASSETS:
  Income tax benefit........................................    77,981     59,020
  Deferred financing costs, net of accumulated
     amortization...........................................     7,991      8,547
  Notes receivable from affiliates..........................     4,891      5,801
  Other.....................................................    30,619      5,934
                                                              --------   --------
          Total other assets................................   121,482     79,302
                                                              --------   --------
          Total Assets......................................  $633,347   $535,488
                                                              ========   ========
                      LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
  Accounts payable..........................................  $    167   $  7,452
  Accrued liabilities.......................................    65,417     25,346
  Accrued dividends.........................................     8,683      7,398
                                                              --------   --------
          Total current liabilities.........................    74,267     40,196
                                                              --------   --------
LONG-TERM LIABILITIES:
  Notes payable to affiliates...............................    76,410     54,528
  Long-term debt............................................   337,504    335,787
  Other.....................................................    22,571     17,114
                                                              --------   --------
          Total long-term liabilities.......................   436,485    407,429
                                                              --------   --------
          Total liabilities.................................   510,752    447,625
                                                              --------   --------
SHAREHOLDERS' EQUITY:
  Common Stock..............................................       130        130
  Accumulated earnings......................................   122,465     87,733
                                                              --------   --------
          Total shareholders' equity........................   122,595     87,863
                                                              --------   --------
          Total Liabilities and Shareholders' Equity........  $633,347   $535,488
                                                              ========   ========
</TABLE>

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

                                       63
<PAGE>   64

                                                                      SCHEDULE I

                             COGENTRIX ENERGY, INC.
                  CONDENSED STATEMENTS OF INCOME OF REGISTRANT
              FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
                             (DOLLARS IN THOUSANDS)

<TABLE>
<CAPTION>
                                                                1999       1998       1997
                                                              --------   --------   --------
<S>                                                           <C>        <C>        <C>
INCOME:
  Development and construction management fees..............  $    618   $  4,471   $  5,329
  Operating management fees.................................    23,618     22,836     20,002
                                                              --------   --------   --------
          Total income......................................    24,236     27,307     25,331
                                                              --------   --------   --------
OPERATING EXPENSES:
  General, administrative and development expenses..........    37,981     34,310     40,765
  Depreciation and amortization.............................     2,115      1,467      1,304
                                                              --------   --------   --------
          Total operating expenses..........................    40,096     35,777     42,069
                                                              --------   --------   --------
OPERATING LOSS..............................................   (15,860)    (8,470)   (16,738)
                                                              --------   --------   --------
OTHER INCOME (EXPENSE):
  Interest expense..........................................   (34,466)   (15,018)   (10,635)
  Investment and other income...............................     1,456        236      2,137
                                                              --------   --------   --------
          Total other expense...............................   (33,010)   (14,782)    (8,498)
                                                              --------   --------   --------
LOSS BEFORE INCOME TAXES....................................   (48,870)   (23,252)   (25,236)
INCOME TAX BENEFIT..........................................    18,962      9,255      9,413
EQUITY IN EARNINGS OF SUBSIDIARIES..........................    73,323     50,986     30,604
                                                              --------   --------   --------
NET INCOME..................................................  $ 43,415   $ 36,989   $ 14,781
                                                              ========   ========   ========
</TABLE>

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

                                       64
<PAGE>   65

                                                                      SCHEDULE I

                             COGENTRIX ENERGY, INC.
                CONDENSED STATEMENTS OF CASH FLOWS OF REGISTRANT
              FOR THE YEAR ENDED DECEMBER 31, 1999, 1998 AND 1997
                             (DOLLARS IN THOUSANDS)

<TABLE>
<CAPTION>
                                                                1999       1998        1997
                                                              --------   ---------   --------
<S>                                                           <C>        <C>         <C>
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES.............  $ 94,508   $  78,803   $ 36,860
                                                              --------   ---------   --------
CASH FLOWS FROM INVESTING ACTIVITIES
  (Increase) decrease in restricted investments.............        --         250     19,750
  Property, plant and equipment additions...................      (389)     (2,485)      (201)
  Investments in subsidiaries...............................   (88,193)   (301,077)   (46,239)
                                                              --------   ---------   --------
  Net cash flows used in investing activities...............   (88,582)   (303,312)   (26,690)
                                                              --------   ---------   --------
CASH FLOWS FROM FINANCING ACTIVITIES
  Proceeds (repayment) from notes payable to affiliate,
     net....................................................    21,882      10,123    (10,878)
  Increase in restricted cash...............................      (198)     (4,940)       (22)
  Proceeds from issuance of long term debt..................        --     233,705         --
  Decrease (increase) in notes receivable from affiliates...       910       1,325     (3,612)
  Increase in deferred financing costs......................      (763)     (6,944)      (661)
  Dividends paid............................................    (7,398)     (2,140)    (5,000)
                                                              --------   ---------   --------
  Net cash flows provided by (used in) financing
     activities.............................................    14,433     231,129    (20,173)
                                                              --------   ---------   --------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........    20,359       6,620    (10,003)
CASH AND CASH EQUIVALENTS, beginning of year................    14,884       8,264     18,267
                                                              --------   ---------   --------
CASH AND CASH EQUIVALENTS, end of year......................  $ 35,243   $  14,884   $  8,264
                                                              ========   =========   ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
  CASH DIVIDENDS RECEIVED...................................  $141,873   $  97,605   $ 59,291
                                                              ========   =========   ========
</TABLE>

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

                                       65
<PAGE>   66

                                                                      SCHEDULE I

                             COGENTRIX ENERGY, INC.

             NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT

1. SIGNIFICANT ACCOUNTING POLICIES

     These condensed notes should be read in conjunction with the consolidated
financial statements and accompanying notes.

     Accounting for Subsidiaries -- Cogentrix Energy, Inc. 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.

     Change of Fiscal Year -- Effective January 1, 1998, Cogentrix Energy, Inc.
changed its fiscal year to commence on January 1 and conclude on December 31 of
each year. Cogentrix Energy, Inc.'s fiscal year previously commenced each July
1, concluding on June 30 of the following calendar year. Cogentrix Energy has
restated its financial statements for the years ending December 31, 1997 fiscal
year to a calendar year basis.

2. LONG-TERM DEBT

  Senior Notes

     On March 15, 1994, Cogentrix Energy, Inc. 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, Inc. 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 which has been deferred and
included as part of the 2004 Notes on the accompanying consolidated balance
sheets. This deferred gain will be recognized over the term of the 2004 Notes,
reducing the effective rate of interest on the 2004 Notes to 7.5%. The 2004
Notes require annual sinking fund payments beginning in March 2001. 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, Inc. 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 rate of approximately
8.824%. 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%.

                                       66
<PAGE>   67
                             COGENTRIX ENERGY, INC.

      NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT -- (CONTINUED)

     Future maturities of long-term debt at December 31, 1999, excluding the
unamortized balance of the net deferred hedge loss and excluding the net
unamortized premium, are as follows (dollars in thousands):

<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
------------
<S>                                                       <C>
2000....................................................    $      0
2001....................................................      20,000
2002....................................................      20,000
2003....................................................      20,000
2004....................................................      20,000
Thereafter..............................................     275,000
                                                            --------
                                                            $355,000
                                                            ========
</TABLE>

  Corporate Credit Facility

     In May 1997, the Company entered into a credit agreement with Australia and
New Zealand Banking Group Limited, as agent for a group of lending banks. In
October 1998, the Company amended and restated the corporate credit facility to
provide for $125 million of revolving credit available through October 2002 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 currently 50 basis points per
annum, payable each quarter on the outstanding unused portion of the Corporate
Credit Facility. As of December 31, 1999, the Company has used this credit
facility to issue approximately $117 million of letters of credit in connection
with investments made in electric-generating plants, and two plants under
construction. Subsequent to December 31, 1999, the Corporate Credit Facility was
amended to provide for $175 million of revolving credit available through
October, 2002.

     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 2002, unless the term of the credit agreement 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 credit agreement.

                                       67
<PAGE>   68

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
        FINANCIAL DISCLOSURE

     None.

                                    PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

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

<TABLE>
<CAPTION>
                   NAME                     AGE                         POSITION
                   ----                     ---                         --------
<S>                                         <C>   <C>
George T. Lewis, Jr. .....................  72    Chairman Emeritus and Director
David J. Lewis............................  43    Chairman of the Board, Chief Executive Officer and
                                                    Director
Mark F. Miller............................  45    President, Chief Operating Officer and Director
James E. Lewis............................  36    Vice Chairman and Director
Dennis W. Alexander.......................  53    Group Senior Vice President, General Counsel,
                                                  Secretary and Director
James R. Pagano...........................  40    Group Senior Vice President -- Development, Mergers
                                                  & Acquisitions
Bruno R. Dunn.............................  49    Group Senior Vice President -- Operations
Thomas F. Schwartz........................  38    Group Senior Vice President -- Chief Financial
                                                  Officer
Betty G. Lewis............................  70    Director
Robert W. Lewis...........................  46    Director
W. E. "Bill" Garrett......................  69    Director
John A. Tillinghast.......................  72    Director
</TABLE>

     GEORGE T. LEWIS, JR., our founder, has been a Director of Cogentrix Energy
since its formation in 1993 and was appointed Chairman Emeritus in March 1999.
Prior to March 1999, Mr. Lewis was Chairman of the Board since December 1993,
Chief Executive Officer and a Director of Cogentrix, Inc. from 1983 to 1993,
Chairman of the Board of Cogentrix, Inc. since 1990 and President of Cogentrix,
Inc. from 1983 to 1989. Mr. Lewis previously served for over 18 years with Chas
T. Main, Inc., an engineering firm headquartered in Boston. In 1971, he became a
Senior Vice President responsible for that firm's work with the utility
industry. From 1978 through 1980, he headed that firm's Southern District office
located in Charlotte, North Carolina and directed its involvement in the area of
coal-fired industrial power plants. In 1980, Mr. Lewis was promoted to Group
Vice President and director and returned to Boston to assume responsibility for
all corporate marketing and sales. George Lewis is the father of David J. Lewis,
James E. Lewis and Robert W. Lewis and the spouse of Betty G. Lewis.

     DAVID J. LEWIS has been a Director of Cogentrix Energy since its formation
and was appointed Chairman of the Board and Chief Executive Officer in March
1999. Prior to March 1999, Mr. Lewis was Vice Chairman of the Board and Chief
Executive Officer since August 1995, Executive Vice President -- Marketing and
Development, Chief Executive Officer -- Elect since June 1994, Group Senior Vice
President -- Marketing and Development with Cogentrix, Inc. since September 1993
and a Director of Cogentrix, Inc. since 1988. From 1989 until September 1993, he
was Senior Vice President -- CGX Environmental Systems and President and Chief
Operating Officer -- CGX Environmental Systems Division of Cogentrix, Inc. From
1987 to 1989, he was Vice President -- Administration of Cogentrix, Inc. from
1986 to 1987, he was Resident Construction Manager and from 1985 to 1986, he was
Assistant Construction Manager. Prior to joining Cogentrix, Inc. in 1985, he was
Operations Manager with Bartex Corporation, an export management company
headquartered in Portland, Oregon. David Lewis is a son of George T. Lewis, Jr.
and Betty G. Lewis.

                                       68
<PAGE>   69

     MARK F. MILLER was appointed President, Chief Operating Officer and a
Director of Cogentrix Energy in May 1997. Prior to joining Cogentrix Energy, Mr.
Miller was Vice President for Northrop Grumman in Bethpage, New York. He joined
Northrop Grumman in 1982 and held successive positions in the material, law and
contracts departments before being named Vice President, Contracts and Pricing
at Northrop's B-2 Division in 1991. In 1993, he became Vice President-Business
Management at the B-2 Division. In 1994, Northrop acquired the Grumman
Corporation and Mr. Miller was named Vice President-Business Management for the
newly formed Electronics and Systems Integration Division, a position he held
until his move to Cogentrix Energy. From 1980 to 1982, he was an Associate with
the law firm of Dolack, Hansler.

     JAMES E. LEWIS has been a Director of Cogentrix Energy since its formation,
and was appointed Vice Chairman in March 1999. Prior to March 1999, Mr. Lewis
was Executive Vice President since December 1993, Executive Vice President of
Cogentrix, Inc. since November 1992 and a Director of Cogentrix, Inc. since
1988. From 1991 to 1992, he was Senior Vice President of Operations responsible
for the daily operations of Cogentrix, Inc.'s facilities. From 1989 to 1991, Mr.
Lewis was Vice President -- Utility Operations. Mr. Lewis joined Cogentrix in
1986 and in 1987, he was selected as Assistant Project Manager responsible for
the construction of the Portsmouth facility. James Lewis is a son of George T.
Lewis, Jr. and Betty G. Lewis.

     DENNIS W. ALEXANDER has been Group Senior Vice President, General Counsel,
Secretary and a Director since joining Cogentrix Energy in February 1994.
Immediately prior to joining Cogentrix Energy, Mr. Alexander was Vice
President/General Counsel of Wheelabrator Environmental Systems Inc., the waste-
to-energy and cogeneration subsidiary of Wheelabrator Technologies Inc., an
independent power and environmental services and products company, as well as
Director, Environmental, Health and Safety Audit Program for Wheelabrator
Technologies Inc. From 1988 to 1990, Mr. Alexander was Vice President/General
Counsel -- Operations of Wheelabrator Environmental Systems Inc. and from 1986
to 1988 was Vice President/General Counsel of Wheelabrator Energy Systems, a
cogeneration project development subsidiary. From 1984 to 1986, he served as
Group General Counsel for The Signal Company and from 1980 to 1984 as Division
General Counsel of Wheelabrator-Frye Inc., each a diversified public company.

     JAMES R. PAGANO has been Group Senior Vice President -- Development,
Mergers & Acquisitions since February 1999. From May 1997 until then he was
Group Senior Vice President -- Chief Financial Officer of Cogentrix Energy,
prior to which he was Senior Vice President -- Project Finance since February
1995 and Vice President -- Project Finance since Cogentrix Energy's formation.
Previously, Mr. Pagano was Vice President -- Project Finance of Cogentrix, Inc.
since July 1993, Vice President -- Legal and Finance from July 1992 to July
1993, and from January 1992 to July 1992, Mr. Pagano was Vice President and
Assistant General Counsel of Cogentrix, Inc. Prior to joining Cogentrix, Inc. he
was Vice President of The Deerpath Group, Inc., a financial advisory firm. From
1987 to 1990, Mr. Pagano was an Associate with the law firm of Simpson Thacher &
Bartlett.

     BRUNO R. DUNN has been Group Senior Vice President Operations since joining
Cogentrix Energy in January 1999. Immediately prior to joining Cogentrix Energy,
Mr. Dunn was Vice President Operations of Wheelabrator Technologies, Inc., an
independent power and environmental services and product company as well as Vice
President Operations of Wheelabrator Environmental Systems, Inc., the waste to
energy and cogeneration subsidiary of Wheelabrator Technologies. From 1988 to
1995 Mr. Dunn was Vice President Construction for Wheelabrator Technologies,
Inc. From 1980 to 1988 Mr. Dunn was a project manager and/or operations manager
for various Wheelabrator trash-to-energy facilities.

     THOMAS F. SCHWARTZ has been Group Senior Vice President -- Finance and
Chief Financial Officer since December 1999. From March 1997 until then he was
Senior Vice President -- Finance and Treasurer of Cogentrix Energy, prior to
which he was Vice President -- Finance and Treasurer since Cogentrix Energy's
formation. Previously, Mr. Schwartz was Controller of Cogentrix, Inc. since
April 1991. Prior to joining Cogentrix, he was an audit manager with Arthur
Andersen, LLP's Small Business Advisory Division.

     BETTY G. LEWIS has been a Director of Cogentrix Energy since September
1994. Betty Lewis is the spouse of George T. Lewis, Jr.

                                       69
<PAGE>   70

     ROBERT W. LEWIS has been a Director of Cogentrix Energy since its
formation, prior to which he was a Director of Cogentrix, Inc. since 1988. In
April 1991, Mr. Lewis resigned from his positions of Vice Chairman and Secretary
of Cogentrix, Inc. which he had held since March 1991. Since his resignation as
an officer, Mr. Lewis has served as a consultant to us. From October 1990 to
March 1991, Mr. Lewis was Executive Vice President and Secretary. From March
1988 to October 1990, Mr. Lewis was Senior Vice President -- Corporate
Development and Secretary, in which position Mr. Lewis was in charge of
Cogentrix, Inc.'s development efforts. From March 1987 to March 1988, Mr. Lewis
was Senior Vice President -- Administration and Secretary. From September 1983
to March 1987, Mr. Lewis was Vice President -- Administration and Secretary. Mr.
Lewis joined Cogentrix, Inc. in April 1983 and served as Secretary through
September 1983. Robert Lewis is a son of George T. Lewis, Jr. and Betty G.
Lewis.

     W. E. "BILL" GARRETT has been a Director of Cogentrix Energy since its
formation and became a Director of Cogentrix, Inc. in September 1993. Mr.
Garrett served on the staff of the National Geographic Society for 36
years -- the last 10 as Editor-in-Chief of the magazine. As a member of the
Board of Trustees of the National Geographic Society and its Research and
Exploration Committee, he was instrumental in the Society's emergence as the
world's largest educational and scientific institution. He resigned in 1990 and
became the President of the La Ruta Maya Conservation Foundation, which is
involved in cultural and conservation work with the Maya Indians. Mexico,
Guatemala and Italy have honored him with prestigious awards for his work in the
region. Mr. Garrett currently serves on the boards of the National Capital
Bicentennial Celebration, the American Land Conservancy, Partners for Livable
Communities and the Editorial Board of Nature's Best Magazine.

     JOHN A. TILLINGHAST was elected a Director of Cogentrix Energy on March 19,
1998. Mr. Tillinghast served from 1994 through May 1998 as President, Chairman
and CEO of Great Bay Power Corporation, a public utility in Portsmouth, New
Hampshire. He also has served from 1997 through May 1998 as the President,
Chairman and CEO of BayCorp Holdings, Ltd., the holding company for Great Bay
Power Corporation. Since May 1998 Mr. Tillinghast has served as Chairman of
BayCorp Holdings and Great Bay Power. After graduating from Columbia University
in 1949 with BS and MS degrees in mechanical engineering, Mr. Tillinghast began
a 30-year career with American Electric Power Company, rising through the
engineering ranks to become Vice Chairman of the Board in charge of engineering
and construction. Prior to his current position at Bay Corp Holdings, LTD., he
served as Chairman of the Energy Engineering Board of the National Academy of
Sciences, Director of the Edison Electric Institute and is a Fellow of the
American Society of Mechanical Engineers. Mr. Tillinghast is registered as a
professional engineer in nine states and holds two U.S. and seven foreign
patents.

                                       70
<PAGE>   71

ITEM 11.  EXECUTIVE COMPENSATION

     The following table sets forth information for the calendar years ended
December 31, 1999, 1998 and 1997 concerning the annual compensation paid or
accrued by Cogentrix to or for the account of each of the following: (1) the
only person who served as the chief executive officer of Cogentrix during the
fiscal year ended December 31, 1999 and (2) the four most highly compensated
executive officers of Cogentrix incumbent at December 31, 1999, other than the
chief executive officer, for the year then ended (collectively, the "Named
Executive Officers").

                           SUMMARY COMPENSATION TABLE

<TABLE>
<CAPTION>
                                                                                         ALL OTHER COMPENSATION
                                                                                      -----------------------------
                                                                                       RETIREMENT      TERMINATION
                                                        ANNUAL COMPENSATION           CONTRIBUTIONS        OF
NAME AND                      TWELVE-MONTH      -----------------------------------        AND          INCENTIVE
PRINCIPAL POSITION            PERIOD ENDING     SALARY(1)    BONUS(2)      TOTAL        OTHER(3)      AGREEMENTS(4)
------------------          -----------------   ---------   ----------   ----------   -------------   -------------
<S>                         <C>                 <C>         <C>          <C>          <C>             <C>
David J. Lewis............  December 31, 1999   $641,392    $1,254,585   $1,895,977     $120,678        $      0
  Chairman and              December 31, 1998    633,428     1,117,302    1,750,730       62,010               0
  Chief Executive Officer   December 31, 1997    613,960       841,239    1,455,199       58,157         862,329
Mark F. Miller............  December 31, 1999   $387,452    $1,082,227   $1,469,679     $195,580        $      0
  President and Chief       December 31, 1998    386,412       779,057    1,165,469      127,989               0
  Operating Officer         December 31, 1997    249,164       173,046      422,210      193,243               0
James E. Lewis............  December 31, 1999   $378,664    $  902,530   $1,281,194     $ 66,498        $956,366
  Vice Chairman             December 31, 1998    378,788       679,642    1,058,430       32,570               0
                            December 31, 1997    364,524       415,163      779,687       25,831         884,692
James R. Pagano...........  December 31, 1999   $307,240    $1,052,530   $1,359,770     $ 67,048        $      0
  Group Senior Vice         December 31, 1998    291,118       660,227      951,345       29,169               0
 President -- Development,  December 31, 1997    223,532       345,033      568,565       28,412               0
  Mergers & Acquisitions
Dennis W. Alexander.......  December 31, 1999   $295,524    $  878,833   $1,174,357     $ 60,705        $      0
  Group Senior Vice         December 31, 1998    295,328       635,227      930,555       27,922               0
  President and             December 31, 1997    284,086       175,033      459,119       21,845               0
  General Counsel
</TABLE>

---------------

(1) Amounts listed in this column include all fees for service on Cogentrix's
    board of directors.
(2) Amounts listed in this column reflect annual performance bonuses and annual
    distributions under our profit-sharing plan, executive incentive bonus plan
    and facility cash flow incentive compensation agreements discussed below.
    The amounts listed do not include the distributions made under such plan and
    agreements to the Named Executive Officers during any fiscal year in which
    such distribution was earned in the previous fiscal year.
(3) The amounts shown in this column include Cogentrix's matching contributions
    on behalf of the Named Executive Officers to Cogentrix's 401(k) savings plan
    in which all Cogentrix employees are eligible to participate and to a
    non-qualified Supplemental Retirement Savings Plan in which approximately 39
    employees, including all of the Named Executive Officers, participate. The
    amounts shown for Mark F. Miller also include compensation related to
    relocation and a company-provided life insurance policy.
(4) The amounts shown in this column for the year ended December 31, 1997
    include the payments made to David J. Lewis and James E. Lewis related to
    the termination of the facility cash flow incentive compensation agreements,
    net of the awards each of these Named Executive Officers would have
    otherwise received under these plans for the fiscal year ended June 30,
    1997, which amounts are included under the column heading "Bonuses." The
    amount for James E. Lewis for the year ended December 31, 1999 represents
    severance benefits earned under our profit sharing plan related to his
    resignation effective January 1, 2000 from Cogentrix as an employee and
    officer.

                                       71
<PAGE>   72

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 42 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, 1999, David J. Lewis earned $796,971, Mark F. Miller earned
$557,880, James E. Lewis and James R. Pagano each earned $478,183, and Dennis W.
Alexander earned $398,486 under our profit sharing plan. In addition, James E.
Lewis earned $956,366 in severance benefits under our profit sharing plan
related to his resignation from Cogentrix as an executive officer.

     In the event a participant in our profit-sharing plan terminates his or her
employment with Cogentrix (for a reason other than death, total disability,
retirement or termination by Cogentrix for willful misconduct), the participant
is entitled to receive a severance benefit equal to a percentage (ranging from
100% after six years of full-time employment to a maximum of 200% after ten
years or more of full-time employment) of the most recent annual distribution to
which the employee is then entitled. 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, 1999, each of the Named Executive Officers, with
the exception of David J. Lewis, earned $324,347 under the executive incentive
bonus plan.

  Facility Cash Flow Incentive Compensation Agreements

     We previously had in effect non-qualified incentive compensation agreements
with two of the Named Executive Officers, David J. Lewis and James E. Lewis,
each of whom is a director and a shareholder of Cogentrix Energy. These
agreements provided for each of these Named Executive Officers to receive,
through June 30, 2007, annual distributions equal to a designated percentage of
the net cash flow for the fiscal year of two of our facilities. In the fiscal
year ended June 30, 1997, we terminated the facility cash flow incentive
compensation agreements with these Named Executive Officers. In connection with
the termination of these plans, David J. Lewis and James E. Lewis were paid
$1,157,996 and $1,119,816 in the fiscal year ended June 30, 1997, respectively.

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 2000 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 receive annual incentive compensation in an amount determined by
the board of directors, which amount, when combined with the base salary payable
to him, shall be at least sufficient to provide him with total annual
compensation that is competitive with total annual compensation offered by other
similarly situated companies to their employees in comparable positions.
                                       72
<PAGE>   73

     Upon our giving notice, the employment agreement is terminable in the event
a majority of the board of directors terminates Mr. Lewis' employment for cause.
In addition, we may terminate the agreement at any time at our option in the
event that the board determines in its reasonable, good faith judgment, and by a
vote of at least two-thirds of the directors then in office, that the continued
service of Mr. Lewis as Chief Executive Officer of Cogentrix would not be in our
best interest because there has occurred a continued failure by him, whether or
not such failure resulted from his physical or mental incapacity, substantially
to perform his duties, responsibilities or obligations as Chief Executive
Officer after having been given written notice of such failure to perform and
after having failed to improve such performance within the time period specified
in such notice. Mr. Lewis may terminate his employment agreement at any time at
his option in the event of a change of control of Cogentrix.

  Mark F. Miller

     When he joined Cogentrix in May 1997, we entered into an employment
agreement with Mark F. Miller to serve as President and Chief Operating Officer.
Under the employment agreement, Mr. Miller is entitled to a minimum base annual
salary of $350,000, which may be increased 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 to receive a performance bonus each fiscal year,
the level of which is determined in the sole discretion of the Chief Executive
Officer. Such performance bonus can not be less than $80,000 for fiscal 1998 and
$100,000 for fiscal 1999. The employment agreement is for a five year term that
renews automatically for an additional five year term, unless we previously
exercise our right to terminate Mr. Miller's employment. 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
continue to receive base salary, bonus (based upon historical levels) and
distributions under the profit sharing plan through the remainder of the initial
term and renewal term of the employment agreement.

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

     - a change in control of Cogentrix

     - a change in title, authority or duties

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

     If Mr. Miller elects to terminate his employment for good reason, he is
entitled to continue to receive, through the remainder of the initial term and
renewal term of the employment agreement, an amount equal to the average annual
salary, bonus and profit sharing distribution received prior to his termination.

  Dennis W. Alexander

     When he joined Cogentrix in January 1994, we entered into an employment
agreement with Dennis W. Alexander to serve as Senior Vice President, General
Counsel and Secretary and as a member of the Board of Directors. 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. A material change in his title,
authority, duties or current compensation following a change in control of
Cogentrix constitutes a de facto termination by us. In the event we terminate
his employment, Mr. Alexander is entitled to receive, within 30 days of his
termination, a severance payment in an amount equal to his total compensation
received in the prior calendar year, including any fees he received for serving
as a member of the Board of Directors.

  James R. Pagano

     In January 1999, we entered into an employment agreement with James R.
Pagano, Group Senior Vice President -- Development, Mergers & Acquisitions.
Under the employment agreement, Mr. Pagano is entitled to an annual base salary
of $306,000, which may be increased in 1999 or in future years. He is also
entitled to participate in our profit sharing plan, at a level of no less than
0.5% of net income before taxes, and

                                       73
<PAGE>   74

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.
Following a change in control of Cogentrix, we will be deemed to have terminated
Mr. Pagano as the result of

     - a change in his title, authority, duties or location of workplace and
       responsibilities,

     - a reduction in his annual base salary or profit sharing participation or

     - our failure to make any other payment to Mr. Pagano.

     In the event we terminate his employment, Mr. Pagano is entitled to
receive, within 30 days of his termination, a severance payment in an amount
equal to 250% of his total compensation received in the prior calendar year,
including salary, bonuses and profit sharing.

DIRECTORS' COMPENSATION AND CONSULTING AGREEMENTS

     Directors, including employee directors, receive an annual retainer of
$25,000 for service on the board of directors. In addition, for each meeting
attended, each director receives a fee of $1,000. During the year ended December
31, 1999, there were five 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 for
consulting services to be rendered to us.

  George T. Lewis, Jr.

     We previously had in effect a non-qualified incentive compensation
agreement with George T. Lewis, Jr., the Chairman of the Board and a shareholder
of Cogentrix Energy. This agreement provided for Mr. Lewis to receive, through
June 30, 2007, annual distributions equal to a designated percentage of the net
cash flow for the fiscal year of one of our facilities. In the fiscal year ended
June 30, 1997, we terminated the facility cash flow incentive compensation
agreement with Mr. Lewis. In connection with the termination of this plan, Mr.
Lewis was paid $1,247,259 in the fiscal year ended June 30, 1997.

     In August 1995, we entered into a five-year employment and noncompetition
agreement with George T. Lewis, Jr., a shareholder and then Chairman of the
Board. Under the terms of the agreement, Mr. Lewis is required to be fully
available to us during customary business hours for consultations, either in
person or by telephone, with respect to our business and affairs as we may
reasonably call on him to furnish. In addition, the restrictive covenants of the
agreement substantially limit Mr. Lewis' ability to engage in consulting
arrangements for other companies and prohibit his support of any company in the
energy industry. Pursuant to the agreement, Mr. Lewis will receive base
compensation of $618,000, adjusted annually based on an inflationary index, as
well as performance bonuses, the amount of which will be determined in
accordance with our policy by the Chief Executive Officer in consultation with
the Chief Operating Officer. Mr. Lewis received base compensation of $676,672
for the year ended December 31, 1999.

     In the event of Mr. Lewis' death or inability to provide services due to
disability, the agreement shall terminate and we are obligated to continue
making payments to him or to his estate for a period of six months after such
termination. We may terminate this agreement for cause at any time, and Mr.
Lewis may voluntarily terminate this agreement at any time. In either case, Mr.
Lewis shall not be entitled to any further payments or benefits under the
consulting agreement. In the event we terminate this agreement without cause,
Mr. Lewis is entitled to receive all payments and benefits which would have been
earned throughout the term of this consulting agreement.

  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
                                       74
<PAGE>   75

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 agreement for the year ended December 31, 1999 was
$293,265.

     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, employee and officer 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:

<TABLE>
<CAPTION>
                           PERIOD                             BASE COMPENSATION
                           ------                             -----------------
<S>                                                           <C>
01-01-00 to 12-31-00........................................      $350,424
01-01-01 to 12-31-01........................................       219,015
01-01-02 to 12-31-03........................................       187,727
01-01-04 to 12-31-04........................................       125,151
</TABLE>

     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:

<TABLE>
<CAPTION>
                                                                NUMBER OF    PERCENTAGE
                            NAME                                 SHARES      OWNERSHIP
                            ----                                ---------    ----------
<S>                                                             <C>          <C>
George T. Lewis, Jr. (1)....................................     73,320          26%
John C. Fennebresque (2)....................................     73,320          26
Betty G. Lewis..............................................     73,320          26
David J. Lewis..............................................     45,120          16
James E. Lewis..............................................     45,120          16
Robert W. Lewis.............................................     45,120          16
</TABLE>

---------------

(1) George T. Lewis, Jr.'s shares are held of record by a revocable grantor
    trust (the "Trust") that may be revoked by Mr. Lewis at any time prior to
    his death, in which event the shares held by the Trust would be transferred
    to him. Accordingly, he is deemed to be the beneficial owner of the shares
    held by the Trust.
(2) The 73,320 shares shown as beneficially owned by Mr. Fennebresque are all
    held of record by the Trust described in Note 1 above. Mr. Fennebresque is
    deemed to be the beneficial owner of these shares, because he is the sole
    trustee of the Trust and, as such, has the power to vote and invest the
    shares held by the Trust. Since George T. Lewis, Jr. is also deemed to be
    the beneficial owner of these shares, they are also included in the amount
    shown for the number of shares beneficially owned by George T. Lewis, Jr.

                                       75
<PAGE>   76

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

     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, owns and leases certain equipment to our
project subsidiaries related to the operations of the plants. 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 $901,000, $726,000, and $896,000 for the fiscal
years ended December 31, 1999, 1998 and 1997, respectively.

     ELP also owns and leases to us our executive offices under a long term
lease with an initial term expiring in 2004. Total rent paid by us to ELP under
such lease was $868,000, $856,000 and $843,000 for the fiscal years ended
December 31, 1999, 1998 and 1997, respectively.

     ELP leases 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. Total
amounts paid by ELP under such lease were $118,000, $112,000 and $112,000 for
the years ended December 31, 1999, 1998 and 1997, respectively.

FACILITY CASH FLOW INCENTIVE COMPENSATION AGREEMENTS

     We have entered into agreements with four of the beneficial owners of our
outstanding shares of common stock, each of whom is also a director, that
provide for them to receive annual distributions equal to a designated
percentage of the net cash flow for each fiscal year of one or both of two of
our facilities. During the fiscal year ended June 30, 1997, we terminated these
agreements for the three executive officers. See "Executive
Compensation -- Compensation Pursuant to Incentive Compensation Plans --
Facility Cash Flow Incentive Compensation Agreements" and "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.

                                       76
<PAGE>   77

                                    PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

     (a)  Financial Statements, Financial Statement Schedules and
          Exhibits -- The following documents are filed as part of this Form
          10-K.

          (1) Consolidated Financial Statements -- See index on page 37.

          (2) Financial Statement Schedules -- See index on page 37.

          (3) Index to Exhibits.

<TABLE>
<CAPTION>
DESIGNATION OF
   EXHIBIT       DESCRIPTION OF EXHIBIT
--------------   ----------------------
<C>              <S>
      2.1        Purchase Agreement, dated as of March 6, 1998, between
                 Cogentrix Energy, Inc. and Bechtel Generating Company, Inc.
                 (10.2). (*)(13)
      2.1(a)     Amendment No. 1, dated October 14, 1998, to Purchase
                 Agreement, dated March 6, 1998, between Cogentrix Energy,
                 Inc., a North Carolina corporation ("Buyer"), and Bechtel
                 Generating Company, Inc., a Delaware corporation ("Seller").
                 (21)
      2.2        Securities Purchase Agreement, dated March 6, 1998, by and
                 among LS Power Corporation, a Delaware corporation, Granite
                 Power Partners, L.P., a Delaware Limited partnership
                 (collectively, the "Sellers"), Cogentrix Mid-America, Inc.,
                 a Delaware corporation, Cogentrix Cottage Grove, LLC, a
                 Delaware limited liability Company, and Cogentrix
                 Whitewater, LLC, a Delaware limited liability company
                 (collectively, the "Purchasers") and Cogentrix Energy, Inc.
                 (2). (12)
      3.1        Articles of Incorporation of Cogentrix Energy, Inc. (3.1).
                 (1)
      3.2        Amended and Restated Bylaws of Cogentrix Energy, Inc., as
                 amended (3.2). (11)
      4.1        Indenture, dated as of March 15, 1994, between Cogentrix
                 Energy, Inc. and First Union National Bank of North
                 Carolina, as Trustee, including form of 8.10% 2004 Senior
                 Note (4.1). (3)
      4.2        Indenture, dated as of October 20, 1998, between Cogentrix
                 Energy, Inc. and First Union National Bank, as Trustee,
                 including form of 8.75% Senior Note. (4.2) (14)
      4.3        First Supplemental Indenture, dated as of October 20, 1998,
                 between Cogentrix Energy, Inc. and First Union National
                 Bank, as Trustee. (4.3) (14)
      4.4        Registration Agreement, dated as of October 20, 1998, by and
                 among Cogentrix Energy, Inc., Salomon Smith Barney Inc.,
                 Goldman, Sachs & Co. and CIBC Oppenheimer Corp. (4.4) (14)
      4.5        Registration Agreement, dated as of November 25, 1998,
                 between Cogentrix Energy, Inc. and Salomon Smith Barney,
                 Inc. (4.5) (15)
      4.6        Amendment No. 1 to the First Supplemental Indenture, dated
                 as of November 25, 1998, between Cogentrix Energy, Inc. and
                 First Union National Bank, as Trustee. (4.6) (15)
     10.1        Power Purchase and Operating Agreement, dated as of July 21,
                 1986, between Cogentrix of Virginia, Inc. and Virginia
                 Electric and Power Company, as amended (assigned to and
                 assumed by Cogentrix Virginia Leasing Corporation)
                 (Portsmouth Facility) (10.7). (1)
     10.1(a)     Third Amendment and Restatement of the Power Purchase and
                 Operating Agreement, dated December 5, 1997, between
                 Cogentrix Virginia Leasing Corporation and Virginia Electric
                 and Power Company (Portsmouth Facility) (10.7(a)). (11)
     10.2        Power Purchase and Operating Agreement, dated as of January
                 24, 1989, between Cogentrix of Rocky Mount, Inc. and
                 Virginia Electric and Power Company, doing business in North
                 Carolina as North Carolina Power, as amended (Rocky Mount
                 Facility) (10.8). (1)
</TABLE>

                                       77
<PAGE>   78

<TABLE>
<CAPTION>
DESIGNATION OF
   EXHIBIT       DESCRIPTION OF EXHIBIT
--------------   ----------------------
<C>              <S>
     10.3        Power Purchase and Operating Agreement, dated as of January
                 24, 1989, between Cogentrix of Richmond, Inc. (formerly
                 named Cogentrix of Petersburg, Inc.) and Virginia Electric
                 and Power Company, as amended. (Richmond Facility, Unit I)
                 (10.10). (1)
     10.4        Power Purchase and Operating Agreement, dated as of January
                 24, 1989, between WV Hydro, Inc. and Virginia Electric and
                 Power Company, as amended (assigned to and assumed by
                 Cogentrix of Richmond, Inc.) (Richmond Facility, Unit II)
                 (10.11). (1)
     10.5        Steam Purchase Agreement, dated as of December 31, 1985,
                 between Cogentrix Virginia Leasing Corporation and
                 Hoechst-Celanese Corporation (successor to Virginia
                 Chemicals Inc.) (Portsmouth Facility) (10.19). (*)(2)
     10.6        Steam Purchase Agreement, dated as of November 15, 1988,
                 between Cogentrix of Rocky Mount, Inc. and Abbott
                 Laboratories, as amended (Rocky Mount Facility) (10.20).
                 (*)(2)
     10.7        Steam Purchase Agreement, dated as of May 18, 1990, between
                 Cogentrix of Richmond, Inc. and E.I. du Pont de Nemours and
                 Company, as amended (Richmond Facility) (10.22). (*)(2)
     10.8        Coal Sales Agreement, dated as of December 15, 1986, among
                 AgipCoal Sales USA, Inc. (formerly named Enoxy Coal Sales,
                 Inc.), AgipCoal USA, Inc. (formerly named Enoxy Coal, Inc.)
                 and Cogentrix Virginia Leasing Corporation (Portsmouth
                 Facility) (10.27). (*)(2)
     10.8(a)     First Amendment to Coal Sales Agreement, dated September 29,
                 1995, by and between Arch Coal Sales Company, Inc., and
                 Cogentrix Virginia Leasing Corporation (Portsmouth Facility)
                 (10.1). (6)
     10.8(b)     Second Amendment, dated as of April 20, 1999, to Coal Sales
                 Agreement, dated as of December 15, 1986, by and between
                 Cogentrix Virginia Leasing Corporation and Arch Coal Sales
                 Company. (10.1) (*) (25)
     10.9        Coal Sales Agreement, dated as of October 1, 1989, among
                 Agip Coal Sales USA, Inc., Laurel Creek Co., Inc. and
                 Cogentrix of Rocky Mount, Inc., as amended (Rocky Mount
                 Facility) (10.28). (*)(2)
    10.10        Coal Sales Agreement, dated as of February 15, 1990, among
                 Electric Fuels Corporation, Kentucky May Coal Company, Inc.
                 and Cogentrix of Richmond, Inc., as amended (Richmond
                 Facility, Unit I) (10.31). (*)(2)
    10.10(a)     Fourth Amendment to Coal Sales Agreement, dated as of July
                 1, 1998, among Electric Fuels Corporation, Kentucky May Coal
                 Company, Inc. and Cogentrix of Richmond, Inc. (10.10(a)) (*)
                 (22)
    10.11        Coal Sales Agreement, dated as of January 1, 1990, between
                 Coastal Coal Sales, Inc., and Cogentrix of Richmond, Inc.,
                 as amended (Richmond Facility, Unit II) (10.32). (*)(2)
    10.12        Railroad Transportation Contract, dated as of December 22,
                 1986, between Cogentrix Virginia Leasing Corporation, and
                 Norfolk Southern Railway Company, as amended (Portsmouth
                 Facility) (10.39). (*)(2)
    10.13        Barge Transportation Contract, dated as of December 23,
                 1986, between Cogentrix Virginia Leasing Corporation and
                 McAllister Brothers, Inc., as amended (Portsmouth Facility)
                 (10.40). (1)
    10.14        Railroad Transportation Contract, dated as of September 26,
                 1989, between Cogentrix of Rocky Mount, Inc. and CSX
                 Transportation, Inc., as amended (Rocky Mount Facility)
                 (10.41). (*)(2)
    10.14(a)     Fourth Amendment, dated as of August 23, 1995, to the
                 Railroad Transportation Contract, dated as of September 26,
                 1989, between Cogentrix of Rocky Mount, Inc. and CSX
                 Transportation, Inc. (Rocky Mount Facility) (10.41(a)). (5)
</TABLE>

                                       78
<PAGE>   79

<TABLE>
<CAPTION>
DESIGNATION OF
   EXHIBIT       DESCRIPTION OF EXHIBIT
--------------   ----------------------
<C>              <S>
    10.14(b)     Fifth Amendment, dated as of January 1, 1996, to the
                 Railroad Transportation Contract, dated as of September 26,
                 1989, between Cogentrix of Rocky Mount, Inc. and CSX
                 Transportation, Inc. (Rocky Mount Facility) (10.41(b)). (8)
    10.14(c)     Amendment No. 6 to Contract CSXT-C-03951, dated as of
                 January 1, 1997, between Cogentrix of Rocky Mount, Inc. and
                 CSX Transportation, Inc. (Rocky Mount Facility) (10.9). (9)
    10.14(d)     Amendment No. 7 to Contract CSXT-C-03951, dated as of July
                 1, 1997, between Cogentrix of Rocky Mount, Inc. and CSX
                 Transportation, Inc. (Rocky Mount Facility) (10.47(d)). (10)
    10.14(e)     Amendment No. 8 to Contract CSXT-C-03951, dated as of
                 January 1, 1999, between Cogentrix of Rocky Mount, Inc. and
                 CSX Transportation, Inc. (Rocky Mount Facility). (10.14(e))
                 (22)
    10.15        Railroad Transportation Contract, dated as of March 1, 1990,
                 between Cogentrix of Richmond, Inc. and CSX Transportation,
                 Inc., as amended (Richmond Facility, Unit I) (10.42). (*)(2)
    10.15(a)     Third Amendment to Railroad Transportation Contract, filed
                 with the ICC on December 13, 1994, between Cogentrix of
                 Richmond, Inc. and CSX Transportation, Inc. (Richmond
                 Facility, Unit I) (10.4). (4)
    10.16        Railroad Transportation Contract, dated as of March 1, 1990,
                 between Cogentrix of Richmond, Inc. and CSX Transportation,
                 Inc., as amended (Richmond Facility, Unit II) (10.43).
                 (*)(2)
    10.16(a)     Fourth Amendment to Railroad Transportation Contract, filed
                 with the ICC on December 13, 1994, between Cogentrix of
                 Richmond, Inc. and CSX Transportation, Inc. (Richmond
                 Facility, Unit II) (10.5). (4)
    10.16(b)     Fifth Amendment to Railroad Transportation Contract,
                 effective as of November 16, 1995, between Cogentrix of
                 Richmond, Inc. and CSX Transportation, Inc. (Richmond
                 Facility, Unit II) (10.43(b)). (*)(8)
    10.16(c)     Amendment No. 6 to Railroad Transportation Contract,
                 effective on June 9, 1998, between Cogentrix of Richmond,
                 Inc. and CSX Transportation, Inc. (Richmond Facility).
                 (*)(14)
    10.17        Third Amended and Restated Loan Agreement, dated as of
                 December 22, 1997, among Cogentrix Virginia Leasing
                 Corporation, the lenders party thereto and Credit Lyonnais,
                 as the Agent, Issuing Bank and a Lender (Portsmouth
                 Facility) (10.54). (11)
    10.17(a)     Amendment No 1 to the Third Amended and Restated Loan
                 Agreement dated December 22, 1997 between Cogentrix Virginia
                 Leasing Company and several banks and other financial
                 institutions. (10.2) (25)
    10.18        Amended and Restated Construction and Term Loan Agreement,
                 dated as of December 1, 1993, among Cogentrix of Rocky
                 Mount, Inc., the Tranche B Lenders party thereto, and The
                 Prudential Insurance Company of America, as Credit Facility
                 Agent (Rocky Mount Facility) (10.52). (1)
    10.18(a)     First Amendment, dated as of March 31, 1996, to the Amended
                 and Restated Construction and Term Loan Agreement, dated as
                 of December 1, 1993, among Cogentrix of Rocky Mount, Inc.,
                 the Tranche B Lenders party thereto, and The Prudential
                 Insurance Company of America, as Credit Facility Agent
                 (Rocky Mount Facility) (10.4). (7)
    10.18(b)     Second Amendment, dated as of May 31, 1996, to the Amended
                 and Restated Construction and Term Loan Agreement, dated as
                 of December 1, 1993, among Cogentrix of Rocky Mount, Inc.,
                 the Tranche B Lenders party thereto, and The Prudential
                 Insurance Company of America, as Credit Facility Agent
                 (Rocky Mount Facility) (10.48(b)). (8)
</TABLE>

                                       79
<PAGE>   80

<TABLE>
<CAPTION>
DESIGNATION OF
   EXHIBIT       DESCRIPTION OF EXHIBIT
--------------   ----------------------
<C>              <S>
    10.18(c)     Third Amendment, dated as of December 1, 1997, to the
                 Amended and Restated Construction and Term Loan Agreement,
                 dated as of December 1, 1993, among Cogentrix of Rocky
                 Mount, Inc, the Tranche B Lenders party thereto, and The
                 Prudential Insurance Company of America, as Credit Facility
                 Agent (Rocky Mount Facility) (10.55(c)). (11)
    10.19        Amended and Restated Subordinated Note dated April 22, 1994
                 of Cogentrix of Pennsylvania, Inc. payable to Cogentrix
                 Delaware Holdings, Inc. (10.57). (11)
    10.20        Reimbursement and Loan Agreement, dated as of December 1,
                 1990, among Cogentrix of Richmond, Inc., Banque Paribas, New
                 York Branch as Issuing Bank, the lenders party thereto and
                 Banque Paribas, New York Branch, as Agent, as amended
                 (Richmond Facility) (10.55). (1)
    10.20(a)     Fourth Amendment, dated as of February 15, 1995, to the
                 Reimbursement and Loan Agreement, dated as of December 1,
                 1990, among Cogentrix of Richmond, Inc., Banque Paribas, New
                 York Branch, as Issuing Bank, the lenders party thereto and
                 Banque Paribas, New York Branch, as Agent (Richmond
                 Facility) (10.55(a)). (5)
    10.20(b)     Fifth Amendment, dated as of June 1, 1995, to the
                 Reimbursement and Loan Agreement, dated as of December 1,
                 1990, among Cogentrix of Richmond, Inc., Banque Paribas, New
                 York Branch, as Issuing Bank, the lenders party thereto and
                 Banque Paribas, New York Branch, as Agent (Richmond
                 Facility) (10.55(b)). (5)
    10.20(c)     Sixth Amendment, dated as of March 31, 1996, to the
                 Reimbursement and Loan Agreement, dated as of December 1,
                 1990, among Cogentrix of Richmond, Inc., Banque Paribas, New
                 York Branch, as Issuing Bank, the lenders party thereto and
                 Banque Paribas, New York Branch, as Agent (Richmond
                 Facility) (10.5). (7)
    10.20(d)     Seventh Amendment, dated as of December 1, 1997, to the
                 Reimbursement and Loan Agreement, dated as of December 1,
                 1990, among Cogentrix of Richmond, Inc., Banque Paribas, New
                 York Branch, as Issuing Bank, the lenders party thereto and
                 Banque Paribas, New York Branch, as Agent (Richmond
                 Facility) (10.58(d)). (11)
    10.21        Indenture of Trust, dated as of December 1, 1990, between
                 the Industrial Development Authority of the City of
                 Richmond, Virginia and Sovran Bank, N.A., as Trustee,
                 including First and Second Supplemental Indentures of Trust
                 (Richmond Facility) (10.56). (1)
    10.22        Sale Agreement, dated as of December 1, 1990, between the
                 Industrial Development Authority of the City of Richmond,
                 Virginia and Cogentrix of Richmond, Inc., including First
                 and Second Supplemental Sale Agreements (Richmond Facility)
                 (10.57). (1)
    10.23        Third Amended and Restated Security Deposit Agreement, dated
                 as of December 22, 1997, among Cogentrix Virginia Leasing
                 Corporation, Credit Lyonnais, as Agent and Issuing Bank, and
                 First Union National Bank, as Security Agent (Portsmouth
                 Facility) (10.68). (11)
    10.24        Amended and Restated Security Deposit Agreement, dated as of
                 December 1, 1993, among Cogentrix of Rocky Mount, Inc., The
                 Prudential Insurance Company of America, as Credit Facility
                 Agent and First Union National Bank of North Carolina, as
                 Security Agent (Rocky Mount Facility) (10.65). (1)
    10.25        Security Deposit Agreement, dated as of December 1, 1990,
                 among Cogentrix of Richmond, Inc., Banque Paribas, New York
                 Branch, as Agent and First Union National Bank of North
                 Carolina, as Security Agent (Richmond Facility) (10.67). (1)
    10.25(a)     First Amendment to Security Deposit Agreement, dated
                 December 15, 1993, among Cogentrix of Richmond, Inc., Banque
                 Paribas, New York Branch, as Agent and First Union National
                 Bank of North Carolina, as Security Agent (Richmond
                                     Facility) (10.67(a)). (2)
</TABLE>

                                       80
<PAGE>   81

<TABLE>
<CAPTION>
DESIGNATION OF
   EXHIBIT       DESCRIPTION OF EXHIBIT
--------------   ----------------------
<C>              <S>
    10.26        Third Amended and Restated Pledge Agreement, dated as of
                 December 22, 1997, made by Cogentrix, Inc., as Pledgor, and
                 Credit Lyonnais, as Agent (Portsmouth Facility) (10.79).
                 (11)
    10.27        Ground Lease and Easement, dated as of December 15, 1986,
                 between Virginia Chemicals, Inc., as Lessor and Cogentrix
                 Virginia Leasing Corporation, as Lessee (Portsmouth
                 Facility) (10.94). (1)
    10.28        Ground Lease, dated as of December 13, 1990, between
                 Cogentrix of Richmond, Inc., as Lessee, and E.I. du Pont de
                 Nemours and Company, as Lessor (Richmond Facility) (10.95).
                 (1)
    10.29        Amended and Restated Land Lease Agreement, dated as of
                 February 18, 1988, among Arrowpoint Associates Limited
                 Partnership, as Landlord, and Cogentrix, Inc., CI
                 Properties, Inc. and Equipment Leasing Partners, as Tenant,
                 as amended (assigned to and assumed by Equipment Leasing
                 Partners, with Cogentrix, Inc., as guarantor) (Corporate
                 Headquarters) (10.96). (1)
    10.30        Amended and Restated Lease Agreement, dated as of April 30,
                 1993, among Equipment Leasing Partners, as Landlord,
                 Cogentrix, Inc., as Tenant, and CI Properties, Inc., as
                 amended (Corporate Headquarters) (10.97). (1)
    10.31        Letter Agreement, dated May 25, 1989, among Cogentrix, Inc.,
                 Cogentrix of Richmond, Inc. (formerly named Cogentrix of
                 Petersburg, Inc.), and WV Hydro, Inc., as amended (Richmond
                 Facility) (10.98). (1)
    10.32        Consulting Agreement, dated as of September 27, 1991,
                 between Robert W. Lewis and Cogentrix, Inc., as amended
                 (assigned to and assumed by Cogentrix Energy, Inc.) (10.99).
                 (1)
    10.33        Consulting Agreement, dated as of September 30, 1993,
                 between Cogentrix, Inc. and W.E. Garrett (assigned to and
                 assumed by Cogentrix Energy, Inc.) (10.100). (1)
    10.34        Consulting Agreement, dated as of March 19, 1998, between
                 Cogentrix Energy and John A. Tillinghast.
    10.35        Form of Profit-Sharing Plan (I) (10.102). (1)
    10.36        Form of Profit-Sharing Plan (II) (10.103). (1)
    10.37        Executive Incentive Bonus Plan (10.104). (2)
    10.38        Facility Cash Flow Incentive Compensation Agreement with
                 Robert W. Lewis (10.105). (1)
    10.39        Adoption of Stock Transfer Agreement dated as of December
                 30, 1993 among Cogentrix Energy, Inc., Cogentrix Inc., David
                 J. Lewis, Robert W. Lewis and James E. Lewis (10.111). (1)
    10.40        Employment Agreement, dated as of June 24, 1994, between
                 David J. Lewis and Cogentrix Energy, Inc. (10.115). (3)
    10.41        Employment Agreement, dated as of May 1, 1997, between Mark
                 F. Miller and Cogentrix Energy, Inc. (10.109). (10)
    10.42        Employment Agreement, dated as of January 1, 1994, between
                 Dennis W. Alexander and Cogentrix Energy, Inc. (10.110).
                 (11)
    10.43        Executive Employment Agreement, dated as of January 1, 1999,
                 Cogentrix Energy, Inc. and James R. Pagano. (10.42). (22)
    10.44        Supplemental Retirement Savings Plan (10.132). (5)
    10.44(a)     Amendments to Cogentrix Energy, Inc. Supplemental Retirement
                 Savings Plan. (10.3) (26)
</TABLE>

                                       81
<PAGE>   82

<TABLE>
<CAPTION>
DESIGNATION OF
   EXHIBIT       DESCRIPTION OF EXHIBIT
--------------   ----------------------
<C>              <S>
    10.45        Trust Under Supplemental Retirement Savings Plan, dated
                 April 17, 1995, by and between Cogentrix Energy, Inc. and
                 Wachovia Bank of North Carolina, N.A. of Winston Salem,
                 North Carolina, as Trustee (10.133). (5)
    10.46        Consulting and Noncompetition Employment Agreement, dated as
                 of August 11, 1995, between Cogentrix Energy, Inc. and
                 George T. Lewis, Jr. (10.135). (5)
    10.47        Support Agreement, dated as of July 14, 1995, from Cogentrix
                 Energy, Inc. to Malconna Company Limited (10.137). (5)
    10.48        Amended and Restated Credit Agreement, dated as of October
                 29, 1998, among Cogentrix Energy, Inc., the several Lenders
                 from time to time parties thereto, Australia and New Zealand
                 Banking Group Limited, CIBC Oppenheimer Corporation and The
                 Bank of Nova Scotia, as Lead Arrangers, and Australia and
                 New Zealand Banking Group Limited, as Agent and as the
                 Issuing Bank. (10.129) (14)
    10.48(a)     Second Amended and Restated Credit Agreement, dated as of
                 March 3, 2000, among Cogentrix Energy, Inc., the several
                 Lenders from time to time parties thereto, Australia and New
                 Zealand Banking Group Limited, CIBC Oppenheimer Corporation
                 and The Bank of Nova Scotia, as Lead Arrangers, and
                 Australia and New Zealand Banking Group Limited, as Agent
                 and as the Issuing Bank.
    10.49        Amended and Restated Guarantee, dated as of October 29,
                 1998, made by Cogentrix Delaware Holdings, Inc., the
                 Guarantor, in favor of the Borrower Creditors. (10.130) (14)
    10.49(a)     Second Amended and Restated Guarantee, dated as of March 3,
                 2000, made by Cogentrix Delaware Holdings, Inc., the
                 Guarantor, in favor of the Borrower Creditors.
    10.50        Amended and Restated Limited Partnership Agreement, dated as
                 of June 30, 1995, among LSP-Cottage Grove, Inc., Granite
                 Power Partners, L.P., and TPC Cottage Grove, Inc. (17)
    10.50(a)     Amendment #1 to the Cottage Grove Partnership Agreement.
                 (18)
    10.50(b)     Consent, Waiver and Amendment No. 2, dated March 20, 1998,
                 to the Amended and Restated Limited Partnership Agreement of
                 LSP-Cottage Grove, L.P. (20)
    10.50(c)     Third Amendment, dated December 11, 1998, to the Amended and
                 Restated Limited Partnership Agreement of LSP-Cottage Grove,
                 L.P. (23)
    10.51        Amended and Restated Partnership Agreement, dated as of June
                 30, 1995, among LSP-Whitewater I, Inc., Granite Power
                 Partners, L.P. and TPC Whitewater, Inc. (17)
    10.51(a)     Consent, Waiver and Amendment No. 1, dated March 20, 1998,
                 to the Amended and Restated Limited Partnership Agreement of
                 LSP-Whitewater Limited Partnership. (20)
    10.51(b)     Second Amendment, dated December 11, 1998, to the Amended
                 and Restated Limited Partnership Agreement of LSP-Whitewater
                 Limited Partnership. (23)
    10.52        Power Purchase Agreement, dated as of May 9, 1994, between
                 Northern States Power Company and LSP-Cottage Grove, L.P.
                 (17)
    10.53        Power Purchase Agreement, dated as of December 21, 1993,
                 between Wisconsin Electric Power Company and LSP-Whitewater
                 Limited Partnership. (17)
    10.53(a)     Amendment to Power Purchase Agreement, dated as of February
                 10, 1994, between Wisconsin Electric Power Company and
                 LSP-Whitewater Limited Partnership. (17)
    10.53(b)     Second Amendment to Power Purchase Agreement, dated as of
                 October 5, 1994, between Wisconsin Electric Power Company
                 and LSP-Whitewater Limited Partnership. (17)
    10.53(c)     Third Amendment to Power Purchase Agreement, dated as of May
                 5, 1995, between Wisconsin Electric Power Company and
                 LSP-Whitewater Limited Partnership. (17)
    10.53(d)     Fourth Amendment to Power Purchase Agreement, dated March
                 18, 1997, between Wisconsin Electric Power Company and
                 LSP-Whitewater Limited Partnership. (19)
</TABLE>

                                       82
<PAGE>   83

<TABLE>
<CAPTION>
DESIGNATION OF
   EXHIBIT       DESCRIPTION OF EXHIBIT
--------------   ----------------------
<C>              <S>
    10.53(e)     Fifth Amendment to Power Purchase Agreement, dated February
                 26, 1998, between Wisconsin Electric Power Company and
                 LSP-Whitewater Limited Partnership. (20)
    10.54        Operations and Maintenance Agreement by and between
                 LSP-Whitewater Limited Partnership as Owner and
                 LSP-Whitewater I, Inc. as Operator dated as of April 15,
                 1999. (10.1) (*) (24)
    10.55        Operations and Maintenance Agreement by and between
                 LSP-Cottage Grove, L.P. as Owner and LSP-Cottage Grove, Inc.
                 as Operator dated as of April 15, 1999. (10.2) (*) (24)
    10.56        Steam Purchase Contract, effective as of January 1, 1999, by
                 and between Celanese Chemical, Inc. and Cogentrix Virginia
                 Leasing Corporation. (10.3) (*) (25)
    10.57        Steam Purchase Contract, effective as of January 1, 1999, by
                 and between BASF Corporation and Cogentrix Virginia Leasing
                 Corporation. (10.4) (*) (25)
    10.58        Credit Agreement, dated as of September 8, 1999, between
                 Cogentrix Eastern America, Inc. and Dresdner Bank, AG, as
                 administrative agent. (10.1) (26)
    10.58(a)     First Amendment, dated as of December 17, 1999, to the
                 Credit Agreement, dated as of September 8, 1999, between
                 Cogentrix Eastern America, Inc. and Dresdner Bank, AG, as
                 administrative agent.
    10.59        Pledge Agreement, dated as of September 8, 1999, between
                 Cogentrix Delaware Holdings, Inc. and Dresdner Bank, AG, as
                 administrative agent. (10.2) (26)
    10.60        Consulting Agreement, dated as of January 1, 2000, between
                 James E. Lewis and Cogentrix Energy, Inc.
     21.1        Direct and Indirect Subsidiaries of Cogentrix Energy, Inc.
     27.1        Financial Data Schedule, which is submitted electronically
                 to the Securities and Exchange Commission for information
                 only, and is not filed.
</TABLE>

---------------

 (*) Certain portions of this exhibit have been omitted pursuant to previously
     approved requests for confidential treatment.
 (1) Incorporated by reference to Registration Statement on Form S-1 (File No.
     33-74254) filed January 19, 1994. The number designating the exhibit on the
     exhibit index to such previously-filed report is enclosed in parentheses at
     the end of the description of the exhibit above.
 (2) Incorporated by reference to Amendment No. 2 to Registration Statement on
     Form S-1 (File No. 33-74254) filed March 7, 1994. The number designating
     the exhibit on the exhibit index to such previously-filed report is
     enclosed in parentheses at the end of the description of the exhibit above.
 (3) Incorporated by reference to the Form 10-K (File No. 33-74254) filed
     September 28, 1994. The number designating the exhibit on the exhibit index
     to such previously-filed report is enclosed in parentheses at the end of
     the description of the exhibit above.
 (4) Incorporated by reference to the Form 10-Q (File No. 33-74254) filed
     February 14, 1995. The number designating the exhibit on the exhibit index
     to such previously-filed report is enclosed in parentheses at the end of
     the description of the exhibit above.
 (5) Incorporated by reference to the Form 10-K (File No. 33-74254) filed
     September 28, 1995. The number designating the exhibit on the exhibit index
     to such previously-filed report is enclosed in parentheses at the end of
     the description of the exhibit above.
 (6) Incorporated by reference to the Form 10-Q (File No. 33-74254) filed
     November 14, 1995. The number designating the exhibit on the exhibit index
     to such previously-filed report is enclosed in parentheses at the end of
     the description of the exhibit above.
 (7) Incorporated by reference to the Form 10-Q (File No. 33-74254) filed May 3,
     1996. The number designating the exhibit on the exhibit index to such
     previously-filed report is enclosed in parentheses at the end of the
     description of the exhibit above.

                                       83
<PAGE>   84

 (8) Incorporated by reference to the Form 10-K (File No. 33-74254) filed
     October 10, 1996. The number designating the exhibit on the exhibit index
     to such previously-filed report is enclosed in parentheses at the end of
     the description of the exhibit above.
 (9) Incorporated by reference to the Form 10-Q (File No. 33-74254) filed
     February 14, 1997. The number designating the exhibit on the exhibit index
     to such previously-filed report is enclosed in parentheses at the end of
     the description of the exhibit above.
(10) Incorporated by reference to the Form 10-K (File No. 33-74254) filed
     September 29, 1997. The number designating the exhibit on the exhibit index
     to such previously-filed report is enclosed in parentheses at the end of
     the description of the exhibit above.
(11) Incorporated by reference to the Form 10-K (File No. 33-74254) filed March
     30, 1998. The number designating the exhibit on the exhibit index to such
     previously-filed report is enclosed in parentheses at the end of the
     description of the exhibit above.
(12) Incorporated by reference to the Form 8-K (File No. 33-74254) filed April
     6, 1998. The number designating the exhibit on the exhibit index to such
     previously-filed report is enclosed in parentheses at the end of the
     description of the exhibit above.
(13) Incorporated by reference to the Form 10-Q (File No. 33-74254) filed May
     15, 1998. The number designating the exhibit on the exhibit index to such
     previously-filed report is enclosed in parentheses at the end of the
     description of the exhibit above.
(14) Incorporated by reference to the Registration Statement on Form S-4 (File
     No. 33-67171) filed November 12, 1998. The number designating the exhibit
     on the exhibit index to such previously file report is enclosed in
     parentheses at the end of the description of the exhibit above.
(15) Incorporated by reference to Amendment No. 1 to the Registration Statement
     on Form S-4 (File No. 33-67171) filed January 27, 1999. The number
     designating the exhibit on the exhibit index to such previously file report
     is enclosed in parentheses at the end of the description of the exhibit
     above.
(16) Incorporated by reference to Amendment No. 3 to the Registration Statement
     on Form S-4 (File No. 33-67171) filed March 15, 1999 by Cogentrix Energy,
     Inc. and Cogentrix Delaware Holdings, Inc. The number designating the
     exhibit on the exhibit index to such previously file report is enclosed in
     parentheses at the end of the description of the exhibit above.
(17) Incorporated by reference to the Registration Statement on Form S-4 (File
     No. 33-95928) filed on August 16, 1995, as amended, or to the Form 10-K
     filed for the fiscal year ended December 31, 1995 by LS Power Funding
     Corporation, LSP-Cottage Grove, L.P. and LSP-Whitewater Limited
     Partnership.
(18) Incorporated by reference to the Form 10-Q (File No. 33-95928) filed August
     12, 1996 by LS Power Funding Corporation, LSP-Cottage Grove, L.P. and
     LSP-Whitewater Limited Partnership.
(19) Incorporated by reference to the Form 10-Q (File No. 33-95928) filed May
     14, 1997 by LS Power Funding Corporation, LSP-Cottage Grove, L.P. and
     LSP-Whitewater Limited Partnership.
(20) Incorporated by reference to the Form 10-K (File No. 33-95928) filed April
     15, 1998 by LS Power Funding Corporation, LSP-Cottage Grove, L.P. and
     LSP-Whitewater Limited Partnership.
(21) Incorporated by reference to the Form 8-K (File No. 33-74254) filed
     November 4, 1998. The number designating the exhibit on the exhibit index
     to such previously-filed report is enclosed in parentheses at the end of
     the description of the exhibit above.
(22) Incorporated by reference to the Form 10-K (File No. 33-74254) filed March
     31, 1999. The number designating the exhibit on the exhibit index to such
     previously-filed report is enclosed in parentheses at the end of the
     description of the exhibit above.
(23) Incorporated by reference to the Form 10-K (File No. 33-95928) filed March
     31, 1999 by LS Power Funding Corporation, LSP-Cottage Grove, L.P. and
     LSP-Whitewater Limited Partnership.
(24) Incorporated by reference to the Form 10-Q (File No. 33-95928) filed May
     17, 1999 by LS Power Funding Corporation, LSP-Cottage Grove, L.P. and
     LSP-Whitewater Limited Partnership. The number designating the exhibit on
     the exhibit index to such previously filed report is enclosed in
     parentheses at the end of the description of the exhibit above.
(25) Incorporated by reference to the Form 10-Q (File No. 33-74254) filed August
     16, 1999. The number designating the exhibit on the exhibit index to such
     previously filed report is enclosed in parentheses at the end of the
     description of the exhibit above.

                                       84
<PAGE>   85

(26) Incorporated by reference to the Form 10-Q (File No. 33-74254) filed
     November 15, 1999. The number designating the exhibit on the exhibit index
     to such previously filed report is enclosed in parentheses at the end of
     the description of the exhibit above.

                                       85
<PAGE>   86

SIGNATURES.

     Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, as amended, Registrant has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.

                                          COGENTRIX ENERGY, INC.
                                          (Registrant)

Date: March 30, 2000                      By:      /s/ DAVID J. LEWIS
                                            ------------------------------------
                                                       David J. Lewis
                                                   Chairman of the Board,
                                            Chief Executive Officer and Director
                                               (Principal Executive Officer)

     Pursuant to the requirements of the Securities Exchange Act of 1934, as
amended, this report has been signed below by the following persons on behalf of
Registrant and in the capacities and on the dates indicated.

<TABLE>
<CAPTION>
                      SIGNATURE                                     TITLE                    DATE
                      ---------                                     -----                    ----
<C>                                                    <S>                              <C>

              /s/ GEORGE T. LEWIS, JR.                 Chairman Emeritus and Director   March 30, 2000
-----------------------------------------------------
                George T. Lewis, Jr.

                 /s/ DAVID J. LEWIS                    Chairman of the Board, Chief     March 30, 2000
-----------------------------------------------------    Executive Officer and
                   David J. Lewis                        Director

                 /s/ MARK F. MILLER                    President, Chief Operating       March 30, 2000
-----------------------------------------------------    Officer and Director
                   Mark F. Miller

                 /s/ BETTY G. LEWIS                    Director                         March 30, 2000
-----------------------------------------------------
                   Betty G. Lewis

                 /s/ JAMES E. LEWIS                    Vice Chairman and Director       March 30, 2000
-----------------------------------------------------
                   James E. Lewis

                                                       Director                         March 30, 2000
-----------------------------------------------------
                   Robert W. Lewis

               /s/ DENNIS W. ALEXANDER                 Group Senior Vice President,     March 30, 2000
-----------------------------------------------------    General Counsel, Secretary
                 Dennis W. Alexander                     and Director

                  /s/ W. E. GARRETT                    Director                         March 30, 2000
-----------------------------------------------------
                    W. E. Garrett

               /s/ JOHN A. TILLINGHAST                 Director                         March 30, 2000
-----------------------------------------------------
                 John A. Tillinghast

               /s/ THOMAS F. SCHWARTZ                  Group Senior Vice President,     March 30, 2000
-----------------------------------------------------    Chief Financial Officer
                 Thomas F. Schwartz                      (Principal Accounting
                                                         Officer)
</TABLE>

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